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Table of Contents

As filed with the Securities and Exchange Commission on January 26, 2015

Registration No. 333-198990

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 6

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Columbia Pipeline Partners LP

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware   4922   51-0658510

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification Number)

5151 San Felipe St., Suite 2500

Houston, Texas 77056

713-386-3701

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

Carrie J. Hightman

Executive Vice President and Chief Legal Officer

801 East 86th Avenue

Merrillville, Indiana 46410

(877) 647-5990

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

David P. Oelman

Gillian A. Hobson

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

Tel: (713) 758-2222

 

Joshua Davidson

Hillary H. Holmes

Baker Botts L.L.P.

910 Louisiana Street

Houston, TX 77002

(713) 229-1234

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of

securities to be registered

 

Amount

to be
registered(1)

  Proposed
maximum
offering price
per unit(2)
 

Proposed
Maximum
Aggregate

Offering Price(1)(2)

 

Amount of

Registration Fee(3)

Common units representing limited partner interests

  46,000,000   $21.00   $966,000,000   $122,329.20

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Based upon the assumed initial public offering price of $21.00.
(3) The Registrant has previously paid $103,040.00 for the registration of $800,000,000 of proposed maximum aggregate offering price in connection with the Registrant’s Registration Statement on Form S-1 (File No. 333-198990) filed on September 29, 2014.

 

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated January 26, 2015

PROSPECTUS

 

 

 

LOGO

Columbia Pipeline Partners LP

40,000,000 Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of common units representing limited partner interests of Columbia Pipeline Partners LP. We were formed by NiSource Inc. and, prior to this offering, there has been no public market for our common units. We are offering common units in this offering. We currently expect the initial public offering price to be between $19.00 and $21.00 per common unit. We have applied to list our common units on the New York Stock Exchange under the symbol “CPPL.”

Investing in our common units involves risks. Please read “Risk Factors ” beginning on page 26.

These risks include the following:

 

 

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

 

 

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

 

 

CPG OpCo LP (“Columbia OpCo”), a partnership between Columbia Energy Group (“CEG”) and us, will be a restricted subsidiary and a guarantor under the credit facility of Columbia Pipeline Group, Inc. (“HoldCo”) and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

 

Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

 

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

 

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

 

 

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

 

 

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

In order to comply with applicable Federal Energy Regulatory Commission (the “FERC”) rate-making policies, we require an owner of our common units to be an Eligible Holder. Eligible Holders are limited partners or types of limited partners whose, or whose owners’, U.S. federal income tax status does not create or is not reasonably likely to create substantial risk of an adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

 

     Per Common Unit      Total  

Public Offering Price

   $                                $                

Underwriting Discount(1)

   $         $     

Proceeds to Columbia Pipeline Partners LP (before expenses)

   $         $     

 

(1) 

Excludes an aggregate structuring fee payable to Barclays Capital Inc. and Citigroup Global Markets Inc. that is equal to 0.5% of the gross proceeds of this offering, or approximately $            . Please read “Underwriting.” The structuring fee will be paid to Barclays Capital Inc. and Citigroup Global Markets Inc. from the gross proceeds of this offering. Please read “Use of Proceeds.”

The underwriters may purchase up to an additional 6,000,000 common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about             , 2015 through the book-entry facilities of The Depository Trust Company.

 

 

Joint Book-Runners

 

Barclays   Citigroup   BofA Merrill Lynch
Goldman, Sachs & Co.   J.P. Morgan   Morgan Stanley   Wells Fargo Securities

Co-Managers

 

BNP PARIBAS   Credit Suisse   RBC Capital Markets   Fifth Third Securities
KeyBanc Capital Markets   MUFG   Mizuho Securities   Scotia Howard Weil   Huntington Investment Company

Prospectus dated         , 2015


Table of Contents

LOGO

 

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Business Strategies

     4   

Competitive Strengths

     5   

System Expansion Opportunities

     6   

Our Relationship with Our Sponsor

     8   

Spin-Off

     9   

Risk Factors

     9   

Our Management

     11   

Summary of Conflicts of Interest and Fiduciary Duties

     11   

Principal Executive Offices

     12   

Formation Transactions and Partnership Structure

     12   

Organizational Structure

     13   

The Offering

     15   

Summary Historical and Pro Forma Financial and Operating Data

     21   

Non-GAAP Financial Measures

     24   

RISK FACTORS

     26   

Risks Inherent in Our Business

     26   

Risks Inherent in an Investment in Us

     44   

Tax Risks to Common Unitholders

     54   

USE OF PROCEEDS

     59   

CAPITALIZATION

     60   

DILUTION

     61   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     63   

General

     63   

Subordinated Units

     66   

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December  31, 2013 and Twelve Months Ended September 30, 2014

     66   

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015

     69   

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

     78   

General

     78   

Operating Surplus and Capital Surplus

     78   

Capital Expenditures

     80   

Subordination Period

     81   

Distributions From Operating Surplus During the Subordination Period

     83   

Distributions From Operating Surplus After the Subordination Period

     83   

General Partner Interest

     84   

Incentive Distribution Rights

     84   

Percentage Allocations of Distributions From Operating Surplus

     84   

IDR Holders’ Right to Reset Incentive Distribution Levels

     85   

Distributions From Capital Surplus

     87   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     88   

Distributions of Cash Upon Liquidation

     88   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     91   

Non-GAAP Financial Measures

     94   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     96   

Overview

     96   

Spin-Off

     97   

Factors and Trends That Impact Our Business

     98   

 

i


Table of Contents

How We Evaluate Our Operations

     102   

Items Affecting Comparability of Our Financial Results

     104   

General Trends and Outlook

     105   

Results of the Predecessor’s Operations

     106   

Liquidity and Capital Resources

     109   

Critical Accounting Policies

     114   

Recently Issued Accounting Pronouncements

     116   

Qualitative and Quantitative Disclosures About Market Risk

     116   

Off Balance Sheet Arrangements

     117   

INDUSTRY OVERVIEW

     118   

Transportation and Storage Services Contractual Arrangements

     119   

U.S. Natural Gas Market Fundamentals

     120   

LNG Market Opportunity

     122   

Overview of the Marcellus and Utica Shales

     123   

BUSINESS

     124   

Overview

     124   

Spin-off

     125   

Business Strategies

     126   

Competitive Strengths

     127   

Our Relationship with Our Sponsor

     128   

Columbia OpCo’s Assets and Operations

     128   

FERC Regulation

     142   

Seasonality

     144   

Environmental and Occupational Health and Safety Regulation

     144   

Pipeline Safety and Maintenance

     148   

Title to Properties and Rights-of-Way

     151   

Insurance

     151   

Facilities

     151   

Employees

     151   

Legal Proceedings

     151   

MANAGEMENT

     152   

Management of Columbia Pipeline Partners LP

     152   

Executive Officers and Directors of Our General Partner

     152   

Director Independence

     154   

Committees of the Board of Directors

     154   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     156   

Compensation Discussion and Analysis

     156   

Long-Term Incentive Plan

     157   

Compensation of Directors

     159   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     160   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     162   

Historical Transactions

     162   

Ownership of General Partner and Limited Partner Interests

     162   

Distributions and Payments to Our General Partner and Its Affiliates

     162   

Arrangements Governing the Transactions

     164   

Omnibus Agreement

     164   

Contracts with Affiliates

     166   

Procedures for Review, Approval and Ratification of Transactions with Related Persons

     167   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     168   

Summary of Applicable Duties

     168   

Conflicts of Interest

     168   

Fiduciary Duties

     174   

 

ii


Table of Contents

DESCRIPTION OF THE COMMON UNITS

     177   

The Units

     177   

Restrictions on Ownership of Common Units

     177   

Transfer Agent and Registrar

     177   

Transfer of Common Units

     178   

THE PARTNERSHIP AGREEMENT

     179   

Organization and Duration

     179   

Purpose

     179   

Cash Distributions

     179   

Capital Contributions

     180   

Voting Rights

     180   

Applicable Law; Forum, Venue and Exclusive Jurisdiction; Reimbursement of Litigation Costs

     181   

Limited Liability

     182   

Issuance of Additional Interests

     183   

Amendment of the Partnership Agreement

     183   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     185   

Dissolution

     186   

Liquidation and Distribution of Proceeds

     186   

Withdrawal or Removal of Our General Partner

     186   

Transfer of General Partner Interest

     188   

Transfer of Ownership Interests in the General Partner

     188   

Transfer of Subordinated Units and Incentive Distribution Rights

     188   

Change of Management Provisions

     188   

Limited Call Right

     189   

Meetings; Voting

     189   

Voting Rights of Incentive Distribution Rights

     190   

Status as Limited Partner

     190   

Ineligible Holders; Redemption

     190   

Indemnification

     191   

Reimbursement of Expenses

     191   

Books and Reports

     191   

Right to Inspect Our Books and Records

     192   

Registration Rights

     192   

UNITS ELIGIBLE FOR FUTURE SALE

     193   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     195   

Taxation of the Partnership

     195   

Tax Consequences of Unit Ownership

     197   

Tax Treatment of Operations

     201   

Disposition of Units

     202   

Uniformity of Units

     204   

Tax-Exempt Organizations and Other Investors

     205   

Administrative Matters

     206   

INVESTMENT IN COLUMBIA PIPELINE PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     209   

UNDERWRITING

     210   

VALIDITY OF OUR COMMON UNITS

     214   

EXPERTS

     214   

WHERE YOU CAN FIND MORE INFORMATION

     214   

FORWARD-LOOKING STATEMENTS

     215   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF COLUMBIA PIPELINE PARTNERS LP

     A-1   

APPENDIX B—ELIGIBLE HOLDER STATUS

     B-1   

APPENDIX C—GLOSSARY OF TERMS

     C-1   

 

iii


Table of Contents

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Forward-Looking Statements” and “Risk Factors.”

 

 

INDUSTRY AND MARKET DATA

The market and statistical data included in this prospectus regarding the natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations, commissioned reports and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

 

iv


Table of Contents

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

Unless the context otherwise requires, references in this prospectus to “Columbia Pipeline Partners,” “we,” “our,” “us” and the “Partnership” refer to Columbia Pipeline Partners LP and its subsidiaries, including CPG OpCo LP, or “Columbia OpCo,” which is a newly created limited partnership formed to own all of our assets. All references in this prospectus to the “Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context refer to the accounting predecessor to Columbia Pipeline Partners LP. The Predecessor is comprised of substantially all of the subsidiaries in NiSource’s Columbia Pipeline Group Operations segment, including its equity method investments in Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C. and Pennant Midstream, LLC. References in this prospectus to “NiSource” refer to NiSource Inc., the ultimate parent of Columbia Pipeline Partners LP. References in this prospectus to “our general partner” refer to CPP GP LLC. References in this prospectus to “our sponsor” or “CEG” refer to Columbia Energy Group, a wholly owned subsidiary of NiSource, which historically owned substantially all of the natural gas transmission and storage assets of NiSource. References in this prospectus to “HoldCo” refer to Columbia Pipeline Group, Inc., a recently formed Delaware corporation, through which NiSource will hold its interest in us and our general partner.

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner and the limited partner interests in us that are not owned by the public. Even if the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG.

Columbia Pipeline Partners LP

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. Our business and operations will be conducted through Columbia OpCo, a recently formed partnership between CEG and us. At the completion of this offering, our assets will consist of a 14.6% limited partner interest in Columbia OpCo, as well as the non-economic general partner interest in Columbia OpCo. Through our ownership of Columbia OpCo’s general partner, we will control all of Columbia OpCo’s assets and operations.

Columbia OpCo owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2013, 93% of Columbia OpCo’s revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years.

 

 

1


Table of Contents

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. Please read “—System Expansion Opportunities” for additional information about our organic growth opportunities. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited partner interests in Columbia OpCo in connection with its issuance of any new equity interests.

Interstate Pipeline and Storage Assets. Through our ownership interests in Columbia OpCo, we own the following natural gas transportation and storage assets, which are regulated by the Federal Energy Regulatory Commission (the “FERC”):

 

   

Columbia Gas Transmission, LLC (“Columbia Gas Transmission”). Columbia OpCo owns 100% of the ownership interests in Columbia Gas Transmission, which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shales and other producing basins to the midwest, mid-Atlantic and northeast regions. The system consists of approximately 11,200 miles of natural gas transmission pipeline, 89 compressor stations with 617,185 horsepower of installed capacity and approximately 3,400 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

 

   

Columbia Gulf Transmission, LLC (“Columbia Gulf”). Columbia OpCo owns 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with approximately 3,400 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus and Utica shales, Columbia Gulf has recently executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. Once these projects are completed, the system will be able to receive Marcellus and Utica supplies through upstream pipelines such as Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including liquefied natural gas (“LNG”) export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

 

   

Millennium Pipeline Joint Venture (“Millennium Pipeline”). Columbia OpCo owns a 47.5% ownership interest in Millennium Pipeline Company, L.L.C., which transports an average of 1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

 

   

Hardy Storage Joint Venture (“Hardy Storage”). Columbia OpCo owns a 49% ownership interest in Hardy Storage Company, LLC, which owns an underground natural gas storage field in Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth. Columbia Hardy Corporation, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% ownership interest, respectively, in Hardy Storage.

 

 

2


Table of Contents

Gathering, Processing and Other Assets. Through our ownership interests in Columbia OpCo, we own the following gathering, processing and other assets:

 

   

Columbia Midstream Group, LLC (“Columbia Midstream”). Columbia OpCo owns 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 104 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale plays.

 

   

Pennant Midstream, LLC (“Pennant”). Columbia OpCo owns a 50% ownership interest in Pennant, which owns approximately 43 miles of wet natural gas gathering pipeline infrastructure, a gas processing facility and a natural gas liquids (“NGLs”) pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp Energy Company (“Hilcorp”) jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

 

   

Columbia Energy Ventures, LLC (“CEVCO”) and Other. Columbia OpCo owns 100% of the ownership interests in CEVCO, which manages Columbia OpCo’s mineral rights positions in the Marcellus and Utica shales. CEVCO owns production rights to over 450,000 acres and has sub-leased the production rights in four storage fields and has also contributed its production rights in one other field. In addition, Columbia OpCo owns 100% of the ownership interests in CNS Microwave, Inc. (“CNS Microwave”), which provides ancillary communication services to us and third parties.

The following table sets forth selected data for Columbia OpCo’s primary assets as of December 31, 2013:

 

     Miles of Pipeline      Total Annual
Throughput
(MMDth)
     % of
Transportation
Revenue
Generated Under
Firm Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Pipeline Assets:

          

Columbia Gas Transmission

     11,161         1,354         99     5.7   

Columbia Gulf

     3,400         643         95     3.7   

Millennium Pipeline(1)

     253         362         99     6.5   

 

     Working
Storage
Capacity
(MMDth)
     Total  Annual
Withdrawal
(MMDth)
     Total  Annual
Injection
(MMDth)
     % of
Storage
Revenue
Generated
Under Firm
Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Storage Assets:

             

Columbia Gas Transmission

     287         260         236         96     4.5   

Hardy Storage(1)

     12         11         11         100     9.3   

 

     Miles of Pipeline      Processing
Capacity (MMcf/d)
     % of
Transportation
Revenue
Generated Under
Firm Contracts
    Weighted Average
Remaining
Contract Life

(years)
 

Gathering & Processing:

          

Columbia Midstream

     104                   N/A                   100     7.7   

Pennant(1)

     43                   200                   100     10.0   

 

(1) 

Table data represents 100% of the assets shown. Columbia OpCo owns a 47.5%, 49% and 50% ownership interest, respectively, in Millennium Pipeline, Hardy Storage and Pennant. CEG owns a 1% ownership interest in Hardy Storage.

 

 

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Cash Available for Distribution(1)

The following chart sets forth the estimated contribution to our forecasted cash available for distribution for the twelve months ended December 31, 2015 from each of Columbia OpCo’s primary assets:

 

LOGO

 

 

(1) 

Represents a percentage of cash available for distribution for the twelve months ended December 31, 2015 for Columbia OpCo. Please read “Cash Distribution Policy and Restrictions on Distributions” for important information as to the assumptions we have made regarding our financial forecast and for a reconciliation of cash available for distribution to net income. Our forecast, including the percentages shown, is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma combined financial statements and accompanying notes included elsewhere in this prospectus, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors.”

Business Strategies

Our principal business objective is to increase the quarterly cash distribution that we pay to our unitholders over time while ensuring the ongoing stability of our cash flows. We expect to achieve this objective through the following business strategies:

Capitalize on organic expansion opportunities. Our assets are strategically located within close proximity to growing production from the Marcellus and Utica shales and growing demand centers, providing us with substantial organic expansion opportunities. We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. We intend to leverage our management team’s expertise in constructing, developing and optimizing our assets in order to increase and diversify our customer base, increase natural gas supply on our system and maximize volume throughput.

Increase our ownership interest in Columbia OpCo. We intend to increase cash flows by increasing our ownership interest in Columbia OpCo over the next several years pursuant to our preemptive right to purchase any newly issued equity interests in Columbia OpCo. We expect Columbia OpCo to issue a significant amount of

 

 

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new equity interests over the next several years to fund approximately $4.9 billion in estimated capital costs for organic growth projects that we expect will be completed by the end of 2018, and we expect to exercise our preemptive right to purchase these newly issued equity interests to the extent we have financing available. We also have a right of first offer with respect to acquiring CEG’s retained 85.4% limited partner interest in Columbia OpCo if CEG decides to sell such interest. We do not expect CEG to sell its retained limited partner interest in Columbia OpCo in the near term.

Maintain and grow stable cash flows supported by long-term, fee-based contracts. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio to minimize our direct commodity price exposure. We will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications. Substantially all of the $4.9 billion in estimated capital costs for organic growth projects that we expect Columbia OpCo to complete by the end of 2018 are supported by long-term service contracts and binding precedent agreements.

Target a conservative and flexible capital structure. We intend to target credit metrics consistent with the profile of investment grade midstream energy companies although we do not expect to immediately seek a rating on our debt. Furthermore, we intend to maintain a balanced capital structure while financing the capital required to (i) contribute substantially all of the capital required to finance Columbia OpCo’s organic expansion projects, (ii) increase our ownership interest in Columbia OpCo and (iii) pursue potential third-party acquisitions.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

Strategically-located assets. As a result of the geographic location of our operations, we are uniquely positioned to capitalize on both the growing natural gas production volumes in the Marcellus and Utica shales and the increasing demand for transportation, storage and related midstream services from new and existing customers. In addition, our assets provide a unique footprint from the Marcellus/Utica region to the Gulf of Mexico, where the majority of the natural gas liquefaction facilities for LNG export have been announced, positioning us to capitalize on the growing LNG export market.

Integrated service offerings, providing increased revenue opportunities. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, processing, compression, transportation and storage. Our ability to move producers’ natural gas and NGLs from the wellhead to market allows us to earn revenue from multiple services related to a single supply of natural gas and take advantage of incremental revenue opportunities that present themselves along the value chain. Providing multiple services benefits us in attracting new customers while providing us with a better understanding of each customer’s needs and the marketplace. In addition, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers’ demand for natural gas. We believe the integrated nature of our operations and the broad range of services we provide to customers allows us to compete effectively with other pipeline, storage and midstream companies that operate in our marketplace.

Stable and predictable cash flows. We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices. For the year ended December 31, 2013, approximately 93% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years. Furthermore, a significant portion of our cash flows are generated from contracts with creditworthy customers including local distribution companies (“LDCs”), municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters.

 

 

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Financial flexibility to pursue growth opportunities. We have entered into a new $500 million credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility. This facility, which will initially be undrawn, when combined with our expected ability to access the capital markets, should enable us to fund our organic capital investment projects, purchases of additional equity in Columbia OpCo and third-party acquisitions.

Our relationship with our Sponsor. Our relationship with CEG provides us with access to CEG’s extensive operational and commercial expertise. CEG owns our general partner, a majority of our limited partner interests and all of our incentive distributions rights (“IDRs”), as well as a retained 85.4% limited partner interest in Columbia OpCo. As a result of these ownership interests, we believe that CEG is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.

Experienced management team with a proven record of asset operation, construction, development and integration expertise. Our management team has an average of approximately 25 years of experience in the energy industry and a proven record of successfully managing, operating, developing, building, acquiring and integrating transportation, storage and other midstream assets. Our management team has established strong relationships with producers, marketers, LDCs and other end-users of natural gas throughout the upstream and midstream industries, which we believe will be beneficial to us in pursuing organic expansion opportunities. Our management team is also committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe our management team provides us with a strong foundation for evaluating growth opportunities and maintaining the integrity and efficiency of Columbia OpCo’s assets and operations.

System Expansion Opportunities

According to an ICF International (“ICF”) study from June 2014, aggregate gas production from the Marcellus and Utica shales is projected to grow to 34 MMDth/d by 2035. Columbia OpCo’s pipelines have already begun to experience increased throughput associated with the recent increase in production from the Marcellus and Utica shales. Substantially all of Columbia Gas Transmission’s expansion projects are supported by long-term firm transportation agreements providing for the transportation of natural gas primarily from the Marcellus and Utica shales totaling over 2.75 MMDth/d of capacity. In addition, Columbia Gulf, acting as a conduit to transport Marcellus and Utica shale gas, as well as gas from other supply basins to southern markets and LNG terminals, has entered into binding precedent agreements for approximately 2.3 MMDth/d of capacity. Certain of these projects are subject to limited conditions precedent. The unique location and capabilities of Columbia OpCo’s pipeline assets place it in a strategically advantageous position to continue to capitalize on expected growth in production from the Marcellus and Utica shales.

To further capitalize on these and other positive trends, Columbia OpCo is pursuing the following significant projects:

 

Project

  Total
Estimated
Capital Costs

($  millions)(1)
  Expected
In-Service
Date
  

Description

Transportation and Storage

      

Giles County

  25   In service    Adds 12.9 miles of 8-inch pipeline and other facilities to provide 46,000 Dth/d of new firm service, which will be provided to a third party located off its Line KA system and into Columbia Gas of Virginia’s system

 

 

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Project

  Total
Estimated
Capital Costs

($  millions)(1)
  Expected
In-Service
Date
  

Description

Line 1570 Expansion

  18   In service    Replaces approximately 19 miles of 20-inch pipeline with 24-inch pipeline and adds two compressors to increase capacity by 99,000 Dth/d

West Side Expansion (Columbia Gas Transmission)

  87   In service    Increases supply takeaway from the Marcellus shale to Leach with piping modifications and compression to add 444,000 Dth/d of capacity

West Side Expansion (Columbia Gulf)(2)

  113   In service    Adds compressor station modifications along Line 100, replaces horsepower of 30,750 at Alexandria, and enhances existing interconnects to provide 540,000 Dth/d of takeaway capacity from Leach, which accesses various Gulf Coast markets

Chesapeake LNG

  33   Second quarter
2015
   Replaces existing LNG peak shaving facilities for 120,000 Dth/d of peak deliverability

East Side Expansion

  275   Third quarter
2015
   Expands facilities along Line 1278 to transport Marcellus production to mid-Atlantic markets with 312,000 Dth/d of additional capacity

Kentucky Power Plant

  24   Second quarter
2016
   Adds 2.7 miles of 16-inch greenfield pipeline from Columbia Gas Transmission’s Line P to a third-party power plant, and other related facilities to provide 72,000 Dth/d of new capacity

Utica Access

  51   Fourth quarter
2016
   Adds 4.7 miles of 20-inch pipeline and bi-directional launchers and receivers to deliver up to 205,000 Dth/d of Utica supply to Columbia Gas Transmission’s highly liquid trading pool, commonly referred to as the “TCO Pool”

Leach XPress

  1,420   Fourth quarter
2017
   Installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system; 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system; and approximately 101,700 horsepower across multiple sites to provide approximately 1,500,000 Dth/d of capacity out of the Marcellus and Utica production regions to the Leach compressor station (“Leach CS”) located on the Columbia Gulf system, TCO Pool, and other markets on Columbia Gas Transmission system

Rayne XPress

  330   Fourth quarter
2017
   Across three major phases, Columbia Gulf will complete compressor station modifications along the mainline from the Rayne compressor station (“Rayne CS”) located on the Columbia Gulf system to Leach CS, replacement of 27,000 horsepower at Rayne CS, and add two greenfield compressor stations totaling 35,000 horsepower to create over 1 MMDth/d of southbound capacity away from Texas Eastern Transmission and Columbia Gas Transmission receipts

 

 

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Project

  Total
Estimated
Capital Costs
($ millions)(1)
  Expected
In-Service
Date
  

Description

Cameron Access

  310   First quarter
2018
   Adds a new 26-mile 36-inch pipeline; a new compressor station; and enhances existing compression to create 800,000 Dth/d of additional capacity into the Cameron LNG terminal

WB XPress

  870   Fourth quarter

2018

   Transports approximately 1.3 MMDth/d of Marcellus shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which includes access to the Cove Point LNG terminal

Gathering and Processing

      

Washington County Gathering

  120   2015 – 2018    Constructs a field gathering system with compression to feed natural gas into Line 1570

Big Pine Expansion

  65   Third quarter
2015
   9 miles of 20-inch pipeline extension, up to 6,000 horsepower compression in the western Pennsylvania shale production region

Modernization

      

Modernization Program

  1,200   Oct 2014 –
Oct 2017
   Various system enhancements to address reliability and integrity pursuant to Columbia Gas Transmission modernization settlement; please read “Business—Columbia OpCo’s Assets and Operations—Columbia Gas Transmission—Tariff Rates.”

Total

  4,941     

 

(1) 

Represents the project cost expected to be incurred prior to the in service date.

(2)

The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

These projects are subject to risks, including unexpected costs or delays. For more information about our system expansion projects, please read “Business—Columbia OpCo’s Assets and Operations” and “Risk Factors—Risks Inherent in Our Business.”

Our Relationship with Our Sponsor

One of our principal strengths is our relationship with CEG. CEG was originally formed as a Delaware corporation in 1926 and, since its acquisition by NiSource in 2000, has owned and operated substantially all of the natural gas transmission and storage assets of NiSource. CEG’s Columbia Pipeline Group has achieved a brand name in the energy infrastructure industry and developed strong relationships with producers, marketers and other end-users of natural gas throughout the upstream and midstream industries. In addition, over the past five years, CEG has implemented internal expansion capital projects totaling over $1.3 billion, of which approximately $1.1 billion was invested over the 2010 to 2013 period. We intend to utilize the significant experience of CEG’s management team to execute our growth strategy, including the construction, development and integration of additional energy infrastructure assets. NiSource is a publicly traded energy holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the midwest to New England.

Following the completion of this offering, CEG will own our general partner, 6,811,398 of our common units, all of our subordinated units and our incentive distribution rights and 85.4% of the limited partner interests

 

 

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in Columbia OpCo. Given CEG’s significant ownership interest in us following this offering, we believe CEG will be motivated to promote and support the successful execution of our business strategies, including the growth of our partnership; however, we can provide no assurances that we will benefit from our relationship with CEG. While our relationship with CEG and its subsidiaries is a significant strength, it is also a source of potential conflicts. Please read “Conflicts of Interest and Fiduciary Duties.”

Spin-off

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo, which is expected to have an investment grade rating. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur or that HoldCo will receive an investment grade rating. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner, 85.4% of the limited partner interests in Columbia OpCo and the limited partner interests in us that are not owned by the public. Even if the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG, our sponsor. Successful completion of the spin-off could impact our business and operations in a number of positive ways, including increased focus of management and resources on our business and operations. However, the spin-off could adversely impact our business by reducing potential access to financial support from HoldCo and CEG or as a result of recruitment and retention employee issues, increased costs associated with HoldCo becoming a standalone public entity and potential limits on our business operations as a result of certain covenants we agree to make in our omnibus agreement in connection with the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Please read “Business — Spin-Off.”

Risk Factors

An investment in our common units involves risks. You should carefully consider the risks described in “Risk Factors” and the other information in prospectus, before deciding whether to invest in our common units.

Risks Inherent in Our Business

 

   

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

 

   

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

 

   

Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

   

Columbia OpCo will initially be party to a money pool agreement with NiSource Finance Corp. (“NiSource Finance”), which will provide Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. After the spin-off, the money pool is expected to be supported by HoldCo’s credit facility as a source of external funding for all participants. If there were insufficient capacity under the HoldCo credit facility to support the financing of Columbia OpCo’s needs, it could have a material adverse effect on us.

 

 

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The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

 

   

The assumptions underlying our forecast of cash available for distribution included in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from those estimates.

 

   

Our only asset is a 14.6% interest in Columbia OpCo, over which we have operating control. Because our interest in Columbia OpCo represents our only cash-generating asset, our cash flow will depend entirely on the performance of Columbia OpCo and its ability to distribute cash to us.

 

   

Our future business opportunities may be limited as a result of our agreement with HoldCo to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that it may enter into with NiSource in connection with the spin-off.

 

   

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to you.

 

   

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.

 

   

Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.

 

   

The credit and risk profiles of our general partner and its ultimate owner, NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo’s debt, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

   

If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Risks Inherent in an Investment in Us

 

   

Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

 

   

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

 

   

Our sponsor and other affiliates of our general partner may compete with us.

 

   

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

   

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

   

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

 

   

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

 

 

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Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

   

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Tax Risk Factors to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

 

   

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

 

   

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, CPP GP LLC, a wholly owned subsidiary of CEG. As a result of owning our general partner, our sponsor will have the right to appoint all of the members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the New York Stock Exchange (“NYSE”). At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. For more information about the executive officers and directors of our general partner, please read “Management.”

Summary of Conflicts of Interest and Fiduciary Duties

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to our sponsor, the owner of our general partner. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our sponsor and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary or other duties by our general partner or its directors or officers. Our partnership agreement permits the board of directors of our general partner to form a conflicts committee of independent directors and to submit to that committee matters that the board believes may involve conflicts of interest. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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Principal Executive Offices

Our principal executive offices are located at 5151 San Felipe St., Suite 2500, Houston, Texas 77056, and our telephone number is 713-386-3701. Our website address will be http://www.columbiapipelinepartners.com. We intend to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission (“SEC”), available, free of charge, through our website, as soon as reasonably practicable after those reports and such other information is electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Formation Transactions and Partnership Structure

We are a Delaware limited partnership formed by NiSource to own and operate certain of the businesses that have historically been conducted by our sponsor.

At or prior to the closing of this offering:

 

   

CEG, our sponsor, will assume the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and NiSource Finance will novate the $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

CEG will contribute substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

we will receive gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units at an assumed initial offering price of $20.00 per unit;

 

   

CEG (which will own all of Columbia OpCo’s limited partner interests) will contribute an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

   

in exchange for CEG’s contribution, we will issue to CEG 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

we will use $45.0 million of the proceeds from this offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

we will use $755.0 million of the proceeds from this offering to purchase from Columbia OpCo an additional approximate 6.2% limited partner interest in Columbia OpCo, resulting in us owning a 14.6% limited partner interest in Columbia OpCo;

 

   

Columbia OpCo will use $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

   

we have entered into a $500 million revolving credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement (the “money pool”) initially with NiSource Finance and, following the spin-off, with HoldCo, under which (i) the participants may pool their funds for investments and short-term borrowings by any participant; and (ii) $750 million of borrowing capacity will be reserved for Columbia OpCo and its subsidiaries to fund expansion capital expenditures and working capital needs, with no amounts drawn at the closing of this offering; and

 

   

we and Columbia OpCo will enter into an omnibus agreement and a service agreement with CEG and its affiliates.

 

 

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We have granted the underwriters a 30-day option to purchase up to an aggregate of 6,000,000 additional common units. Any net proceeds received from the exercise of this option will be used to purchase an additional percentage limited partner interest in Columbia OpCo; Columbia OpCo will use such cash to fund expansion capital expenditures. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo.

Organizational Structure

The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.

 

LOGO

 

 

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     Units      %  

Columbia Pipeline Partners

     

Public Common Units

     40,000,000         42.7 %(1) 

Interests of CEG:

     

Common Units

     6,811,398         7.3 %(1) 

Subordinated Units

     46,811,398         50.0

Non-Economic General Partner Interest

     —           0.0 %(2) 

Incentive Distribution Rights

     —           —      (3) 
  

 

 

    

 

 

 

Total

     93,622,796         100.0

 

(1) 

Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “—Formation Transactions and Partnership Structure” for a description of the impact of an exercise of the option on the common unit ownership percentages.

(2) 

Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions to Our Partners—General Partner Interest.”

(3) 

Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. Incentive distribution rights will be issued to CEG.

 

 

14


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The Offering

 

Common units offered to the public

40,000,000 common units.

 

  46,000,000 common units if the underwriters exercise their option to purchase additional common units in full.

 

Units outstanding after this offering

46,811,398 common units and 46,811,398 subordinated units, each representing an aggregate 50.0% limited partner interest in us (52,811,398 common units and 46,811,398 subordinated units if the underwriters exercise their option to purchase additional common units in full). In addition, our general partner will own a non-economic general partner interest in us.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $755.0 million from this offering (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the $36.0 million underwriting discount, the structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and $5.0 million in offering expenses, to purchase an additional approximate 6.2% limited partner interest in Columbia OpCo, and Columbia OpCo will use $500.0 million of these net proceeds to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. The remaining proceeds it receives from us will be used to fund expansion capital expenditures. The approximate 6.2% interest in Columbia OpCo purchased with the proceeds from this offering, when combined with an approximate 8.4% interest in Columbia OpCo contributed to us in connection with the formation transactions, will result in our ownership of a 14.6% limited partner interest in Columbia OpCo following the closing of the offering.

 

  If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $114.0 million (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to purchase an additional percentage limited partner interest in Columbia OpCo and Columbia OpCo will use such cash to fund expansion capital expenditures. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% additional limited partner interest in Columbia OpCo purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo and our total ownership interest in Columbia OpCo would be 15.6%. Please read “Use of Proceeds.”

 

 

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Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2015 we expect to make a minimum quarterly distribution of $0.1675 per common unit and subordinated unit ($0.67 per common unit and subordinated unit on an annualized basis) to unitholders of record on the applicable record date. For the first quarter that we are publicly traded, we will pay a prorated distribution covering the period from the completion of this offering through March 31, 2015, based on the actual length of that period.

 

  In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.”

 

  Our partnership agreement generally provides that we will distribute cash each quarter during the subordination period in the following manner:

 

   

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.1675, plus any arrearages from prior quarters;

 

   

second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.1675; and

 

   

third, to the holders of common and subordinated units, pro rata, until each unit has received a distribution of $0.192625.

 

  If cash distributions to our unitholders exceed $0.192625 per common unit and subordinated unit in any quarter, our unitholders and CEG, as the holder of our IDRs, will receive distributions according to the following percentage allocations:

 

     Marginal Percentage Interest
in Distributions
 

Total Quarterly Distribution

Target Amount

   Unitholders     CEG
(as holder
of IDRs)
 

above $0.192625 up to $0.209375

     85.0     15.0

above $0.209375 up to $0.25125

     75.0     25.0

above $0.25125

     50.0     50.0

 

  We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.”

 

 

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  On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 was approximately $55.6 million and $50.8 million, respectively. The amount of cash we will need to pay the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering will be approximately $62.7 million (or an average of approximately $15.7 million per quarter). As a result, we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient cash available for distribution to make cash distributions for the twelve months ending December 31, 2015, at the minimum quarterly distribution rate of $0.1675 per unit per quarter ($0.67 per unit on an annualized basis) on all common units and subordinated units outstanding immediately after the closing of this offering. However, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast. In addition, we do not have a legal or contractual obligation to pay quarterly distributions at the minimum quarterly distribution rate or at any other rate and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $0.67 (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2018 and there are no outstanding arrearages on our common units.

 

 

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  Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $1.005 (150.0% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and we have earned that amount plus the related distribution on the IDRs, for any four-quarter period ending on or after March 31, 2016 and there are no outstanding arrearages on our common units.

 

  When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

 

CEG’s right to reset the target distribution levels    

CEG, as the initial holder of our IDRs, will have the right, at any time when there are no subordinated units outstanding and we have made distributions at or above 150.0% of the minimum quarterly distribution for the prior four consecutive whole fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If CEG transfers all or a portion of our IDRs in the future, then the holder or holders of a majority of our IDRs will be entitled to exercise this right. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.

 

  If the target distribution levels are reset, the holders of our IDRs will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our IDRs to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the IDRs for the quarter prior to the reset election. Please read “How We Make Distributions to Our Partners—IDR Holders’ Right to Reset Incentive Distribution Levels.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding

 

 

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units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, our sponsor will own an aggregate of 57.3% of our outstanding units (or 53.8% of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will give our sponsor the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

 

Eligible Holders and redemption

Only Eligible Holders are entitled to own our units and to receive distributions or be allocated income or loss from us. Eligible Holders are limited partners whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel.

 

  We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the common units of any holder that is an Ineligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the lesser of the holder’s purchase price and the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

  Please read “Description of the Common Units—Transfer of Common Units” and “The Partnership Agreement—Non-Taxpaying Holders; Redemption.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017 you will be allocated, on a cumulative basis, an

 

 

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amount of federal taxable income for that period that will be less than 20% of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $0.67 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.14 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the U.S., please read “Material U.S. Federal Income Tax Consequences.”

 

Directed unit program

At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons associated with us, as designated by us. For further information regarding our directed unit program, please read “Underwriting.”

 

Exchange listing

We have applied to list our common units on the NYSE under the symbol “CPPL.”

 

 

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Summary Historical and Pro Forma Financial and Operating Data

The following table shows summary historical financial and operating data of the predecessor of Columbia Pipeline Partners LP (the “Predecessor”) and pro forma financial data of the Partnership for the periods and as of the dates indicated.

The historical financial statements of the Predecessor reflect 100% of the Predecessor’s operations. The assets of the Partnership on the closing date of the offering will consist only of the acquired interest in Columbia OpCo. Columbia OpCo’s assets will consist of the following wholly owned subsidiaries of the Predecessor: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream and CEVCO, as well as equity method investments in Hardy Storage, Millennium Pipeline and Pennant.

The summary historical financial data presented as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 are derived from the audited financial statements of the Predecessor, which are included elsewhere in this prospectus. The summary historical financial data presented as of September 30, 2014 and for the nine months ended September 30, 2014 and 2013 are derived from the unaudited financial statements of the Predecessor, which are included elsewhere in this prospectus. The summary financial data presented as of December 31, 2011 and September 30, 2013 are derived from the unaudited financial statements of the Predecessor, which are not included elsewhere in this prospectus.

The summary pro forma financial data as of September 30, 2014 and for the fiscal year ended December 31, 2013 and the nine months ended September 30, 2014 are derived from the unaudited pro forma combined financial statements of the Partnership. The unaudited pro forma combined statements of operations for the year ended December 31, 2013 and for the nine months ended September 30, 2014 assume this offering and related transactions occurred on January 1, 2013. The unaudited pro forma combined balance sheet as of September 30, 2014 assumes the offering and related transactions occurred on September 30, 2014. The pro forma financial data give pro forma effect to:

 

   

the assumption by CEG, the Partnership’s sponsor, of the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and the novation by NiSource Finance of that $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

the contribution by CEG of substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

the receipt by the Partnership of gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units to the public at an assumed initial offering price of $20.00 per unit in this offering, the midpoint of the price range on the cover of this prospectus;

 

   

the contribution by CEG (which will own all of Columbia OpCo’s limited partner interests) of an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

   

in exchange for CEG’s contribution, the issuance by the Partnership to CEG of 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

the use by the Partnership of $45.0 million of the proceeds from the offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

the use by the Partnership of $755.0 million of proceeds from the offering to purchase from Columbia OpCo an additional approximate 6.2% limited partner interest in Columbia OpCo, resulting in the Partnership owning a 14.6% limited partner interest in Columbia OpCo;

 

   

the use by Columbia OpCo of $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

 

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the entry by the Partnership into a $500 million revolving credit facility, which is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo and under which no amounts will be drawn at the closing of this offering. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

the entry by Columbia OpCo and its subsidiaries into the money pool with NiSource Finance with $750 million of reserved borrowing capacity, under which no amounts will be drawn at the closing of this offering; and

 

   

the entry by the Partnership and Columbia OpCo into an omnibus agreement and a service agreement with CEG and its affiliates.

We have not given pro forma effect to incremental general and administrative expenses of approximately $5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer insurance expenses; and director and officer compensation expenses.

For a detailed discussion of the summary historical financial information contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds,” “Business—Our Relationship with Our Sponsor” and the audited and unaudited historical financial statements of the Predecessor and our unaudited pro forma combined financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

 

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net. Adjusted EBITDA is not calculated or presented in accordance with generally accepted accounting principles (“GAAP”). We explain this measure under “—Non-GAAP Financial Measures” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners  LP
Pro Forma
 
    Year Ended December 31,     Nine Months
Ended September 30,
    Nine  Months
Ended

September 30,
2014
    Year Ended
December 31,

2013
 
    2013     2012     2011         2014             2013          
    (in millions, except per unit and operating data)  

Statement of Operations Data:

             

Total Operating Revenues

  $ 1,179.4      $ 1,000.4      $ 1,005.6      $ 1,006.5      $ 857.6      $ 1,005.4      $ 1,176.7   

Operating Expenses:

             

Operation and maintenance

    507.1        374.2        377.9        477.1        366.7        454.6        481.4   

Operation and maintenance—affiliated

    118.1        105.6        98.3        89.6        82.4        111.1        142.5   

Depreciation and amortization

    106.9        99.3        130.0        87.7        78.9        87.2        106.1   

(Gain)/loss on sale of assets

    (18.6     (0.6     0.1        (20.8     (11.3     (20.8     (18.6

Property and other taxes

    62.2        59.2        56.6        50.3        46.6        50.1        61.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

  $ 775.7      $ 637.7      $ 662.9      $ 683.9      $ 563.3      $ 682.2      $ 773.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

    35.9        32.2        14.6        32.9        25.6        32.9        35.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

  $ 439.6      $ 394.9      $ 357.3      $ 355.5      $ 319.9      $ 356.1      $ 439.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

             

Interest expense—affiliated

    (37.9     (29.5     (29.8     (39.1     (27.6     (5.7     (1.8

Other, net

    17.6        1.5        1.2        8.0        15.3        8.0        22.6   

Income taxes

    152.4        136.9        125.6        119.7        112.4        0.2        0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

  $ 266.9      $ 230.0      $ 203.1      $ 204.7      $ 195.2      $ 358.2      $ 459.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

             

Net income attributable to non-controlling interests

              (305.9     (392.7
           

 

 

   

 

 

 

Net income attributable to Columbia Pipeline Partners LP

            $ 52.3      $ 67.1   
           

 

 

   

 

 

 

 

 

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    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners  LP
Pro Forma
 
    Year Ended December 31,     Nine Months
Ended September 30,
    Nine Months
Ended
September 30,
   

Year

Ended
December 31,

 
    2013     2012     2011         2014             2013         2014     2013  
    (in millions, except per unit and operating data)  

Limited partner interests in net income:

             

Common units

            $ 26.2      $ 33.6   

Subordinated units

            $ 26.1      $ 33.5   

Net income per limited partner unit (basic and diluted):

             

Common units

            $ 0.56      $ 0.72   

Subordinated units

            $ 0.56      $ 0.72   

Balance Sheet Data (at period end):

             

Total assets

  $ 7,261.8      $ 6,623.2      $ 6,142.6      $ 7,806.8      $ 6,997.5      $ 8,014.5     

Net property, plant and equipment

    4,303.4        3,741.5        3,398.7        4,790.1        4,143.5        4,770.4     

Long-term debt-affiliated, excluding amounts due within one year

    819.8        754.7        294.7        1,370.9        754.7        511.6     

Total liabilities

    3,361.9        2,883.7        2,430.6        3,701.4        3,167.2        1,320.8     

Total partners’ net equity

    3,899.9        3,739.5        3,712.0        4,105.4        3,830.3        6,693.7     

Statement of Cash Flow Data:

             

Net cash from (used for):

             

Operating activities

  $ 454.0      $ 474.9      $ 435.3      $ 446.6      $ 316.5       

Investing activities

    (797.4     (455.5     (307.2     (618.6     (527.6    

Financing activities

    343.1        (18.8     (128.1     172.1        210.6       

Other Data:

             

Adjusted EBITDA

  $ 542.7      $ 496.9      $ 491.5      $ 437.9      $ 392.2      $ 438.0      $ 541.6   

Adjusted EBITDA attributable to non-controlling interest

            $ (374.1   $ (462.5

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

            $ 63.9      $ 79.1   

Maintenance capital expenditures

    132.7        209.6        220.0        90.1        80.3       

Expansion capital expenditures

    664.8        280.0        81.5        536.3        476.2       

Operating Data:(1)

             

Contracted firm capacity (MMDth/d)

    12.9        13.2        13.2        12.8        12.7       

Throughput (MMDth)

    1,997.3        2,200.0        2,393.7        1,497.2        1,492.1       

Natural gas storage capacity (MMDth)

    287        283        282        287        287       

 

(1) 

Excludes equity investments.

Non-GAAP Financial Measures

Adjusted EBITDA

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to

 

 

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Adjusted EBITDA are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following tables present a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

     Columbia Pipeline Partners LP
Predecessor Historical
     Columbia Pipeline Partners LP
Pro Forma
 
     Year Ended December 31,     Nine Months
Ended September 30,
     Nine  Months
Ended

September 30,
2014
     Year Ended
December 31,

2013
 
     2013      2012      2011         2014              2013            
     (in millions)  

Net Income

   $ 266.9       $ 230.0       $ 203.1      $ 204.7       $ 195.2       $ 358.2       $ 459.8   

Add:

                   

Interest expense—affiliated

     37.9         29.5         29.8        39.1         27.6         5.7         1.8   

Income taxes

     152.4         136.9         125.6        119.7         112.4         0.2         0.2   

Depreciation and amortization

     106.9         99.3         130.0        87.7         78.9         87.2         106.1   

Distributions of earnings received from equity investees

     32.1         34.9         18.8        27.6         19.0         27.6         32.1   

Less:

                   

Other, net

     17.6         1.5         1.2        8.0         15.3         8.0         22.6   

Equity earnings in unconsolidated affiliates

     35.9         32.2         14.6        32.9         25.6         32.9         35.8   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 542.7       $ 496.9       $ 491.5      $ 437.9       $ 392.2       $ 438.0       $ 541.6   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Less:

                   

Adjusted EBITDA attributable to non-controlling interest

                   374.1         462.5   
                

 

 

    

 

 

 

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

                 $ 63.9       $ 79.1   
                

 

 

    

 

 

 

 

     Columbia Pipeline Partners LP
Predecessor Historical
 
     Year Ended December 31,     Nine Months Ended
September 30,
 
     2013     2012     2011         2014             2013      
     (in millions)  

Net Cash Flows from Operating Activities

   $ 454.0      $ 474.9      $ 435.3      $ 446.6      $ 316.5   

Interest expense—affiliated

     37.9        29.5        29.8        39.1        27.6   

Current taxes

     (27.5     92.2        48.8        50.2        (39.3

Other adjustments to operating cash flows

     6.1        1.4        (4.1     14.3        (2.4

Changes in assets and liabilities

     72.2        (101.1     (18.3     (112.3     89.8   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 542.7      $ 496.9      $ 491.5      $ 437.9      $ 392.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Inherent in Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.1675 per unit, or $0.67 per unit per year, which will require us to have cash available for distribution of approximately $15.7 million per quarter, or $62.7 million per year, based on the number of common and subordinated units that will be outstanding after the completion of this offering. On a pro forma basis, assuming we had completed this offering on January 1, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been approximately $55.6 million and $50.8 million, respectively.

We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate based on, among other things:

 

   

the rates we charge for our transmission, storage and gathering services;

 

   

the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;

 

   

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;

 

   

legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility;

 

   

the imposition of requirements by state agencies that materially reduce the demand of Columbia OpCo’s customers, such as LDCs and power generators, for its pipeline services;

 

   

the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;

 

   

the creditworthiness of our customers;

 

   

the level of Columbia OpCo’s operating and maintenance and general and administrative costs;

 

   

the level of capital expenditures Columbia OpCo incurs to maintain its assets;

 

   

regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region;

 

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successful development of LNG export terminals in the eastern or northeastern U.S., which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system;

 

   

changes in insurance markets and the level, types and costs of coverage available, and the financial ability of our insurers to meet their obligations;

 

   

changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;

 

   

changes in accounting rules and/or tax laws or their interpretations;

 

   

nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and

 

   

changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

   

the level and timing of capital expenditures we or Columbia OpCo makes;

 

   

construction costs;

 

   

fluctuations in our or Columbia OpCo’s working capital needs;

 

   

our or Columbia OpCo’s ability to borrow funds and access capital markets;

 

   

our or Columbia OpCo’s debt service requirements and other liabilities;

 

   

restrictions contained in our or Columbia OpCo’s existing or future debt agreements; and

 

   

the amount of cash reserves established by our general partner.

For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2013 and for the twelve-month period ended September 30, 2014, with shortfalls on our subordinated units of $11.9 million for the year ended December 31, 2013 and $7.1 million for the twelve-month period ended September 30, 2014.

The amount of pro forma cash available for distribution for the year ended December 31, 2013 and for the twelve months ended September 30, 2014 would have been approximately $50.8 million and $55.6 million, respectively. This amount would have been sufficient to pay 100% of the minimum quarterly distribution on all common units for that period. On a pro forma basis, we would have experienced a shortfall of approximately $7.1 million for the twelve-month period ended September 30, 2014 and $11.9 million for the year ended December 31, 2013 relative to the aggregate minimum quarterly distribution for that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2013 and the twelve months ended September 30, 2014, please read “Cash Distribution Policy and Restrictions on Distributions.”

Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

All of our cash will be generated from cash distributions from Columbia OpCo. In connection with the spin-off, HoldCo’s new credit facility will become effective and is expected to have customary covenants and

 

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restrictions on HoldCo and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facility. In addition, HoldCo expects to issue a significant amount of new senior indebtedness and use the proceeds to fund a distribution to NiSource. If requested by HoldCo, Columbia OpCo will guarantee such indebtedness. Under the omnibus agreement, at HoldCo’s request Columbia OpCo will guarantee future indebtedness of HoldCo. There is no agreement between HoldCo and Columbia OpCo limiting the amount of HoldCo indebtedness that Columbia OpCo will be obligated to guarantee. The amount of HoldCo indebtedness in general, as well as the amount that is guaranteed by Columbia OpCo, may limit the ability of Columbia OpCo to borrow to fund its operations, capital expenditures or growth strategy. Furthermore, to the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant operating and financial restrictions. For example, these restrictions could include covenants limiting Columbia OpCo’s ability to:

 

   

make investments and other restricted payments;

 

   

incur additional indebtedness or issue preferred stock;

 

   

create liens;

 

   

sell all or substantially all of its assets or consolidate or merge with or into other companies; and

 

   

engage in transactions with affiliates.

These covenants or any more restrictive covenants agreed to by HoldCo in the future could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. A breach by HoldCo of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing that debt, including Columbia OpCo and its assets. In addition, any acceleration of debt under HoldCo’s bank syndicated credit facility could constitute a default under other HoldCo debt, which Columbia OpCo may also guarantee. If HoldCo’s lenders or other debt creditors were to proceed against Columbia OpCo’s assets, the value of our ownership interests in Columbia OpCo could be significantly reduced which could adversely affect the value of our common units.

HoldCo would not owe us or our unitholders any fiduciary duty in allocating exceptions or baskets to covenants and financial ratios among itself and its guarantors or in amending its debt agreements to include provisions more burdensome to our operations and financing capabilities.

Columbia OpCo will initially be party to a money pool agreement with NiSource Finance, which will provide Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. After the spin-off, the money pool is expected to be supported by HoldCo’s credit facility as a source of external funding for all participants. If there were insufficient capacity under the HoldCo credit facility to support the financing of Columbia OpCo’s needs, it could have a material adverse effect on us.

After the spin-off, Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement with HoldCo, under which borrowing capacity of $750 million has been reserved for Columbia OpCo and its subsidiaries to fund expansion capital expenditures and working capital needs. The ability of HoldCo to make loans under the money pool will be subject to financial covenants in its credit facility. Therefore, Columbia OpCo’s capacity to borrow under the money pool may be adversely impacted by the level of borrowings by HoldCo under its credit agreement and by adverse changes in HoldCo’s financial condition or results of operations, which will be beyond the control of Columbia OpCo and us. In the event HoldCo were to default under its credit facility, HoldCo could lose access to this facility, and thus may not be able to fund a request by Columbia OpCo under the money pool. If Columbia OpCo is unable to obtain needed capital or financing on satisfactory terms to fund its organic growth projects, the amount of cash that Columbia OpCo is able to distribute to us may be reduced, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

 

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The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods when we record net income.

The assumptions underlying our forecast of cash available for distribution included in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from those estimates.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2015. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct, which are discussed in “Cash Distribution Policy and Restrictions on Distributions.”

We estimate that our total cash available for distribution for the twelve-month period ending December 31, 2015 will be approximately $69.0 million, as compared to approximately $50.8 million for the year ended December 31, 2013 and approximately $55.6 million for the twelve-month period ended September 30, 2014, in each case on a pro forma basis. A majority of this expected increase in cash available for distribution is attributable to revenues from additional firm capacity subscriptions associated with our West Side Expansion and Line 1570 projects. To the extent these and our other expansion projects are not placed into service on schedule or we are not able to subscribe additional firm transmission capacity, our revenues during the forecast period will be adversely affected.

Our forecast of cash available for distribution has been prepared by management, and we have not received an opinion or report on it from any independent registered public accountants. The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from that which is forecasted. If we do not achieve our forecasted results, our unit price could decline materially and we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Our only asset is a 14.6% interest in Columbia OpCo, over which we have operating control. Because our interest in Columbia OpCo represents our only cash-generating asset, our cash flow will depend entirely on the performance of Columbia OpCo and its ability to distribute cash to us.

We are a holding company with no material operations and only limited assets, and the source of our earnings and cash flow will consist exclusively of cash distributions from Columbia OpCo. Therefore, our ability to make quarterly distributions to our unitholders will be completely dependent on the performance of Columbia OpCo and its ability to distribute funds to us.

Columbia OpCo’s limited partnership agreement requires it to distribute all of its available cash each quarter, less the amounts of cash reserves that its general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business, to enable it to make distributions to us so that we can make timely distributions or to comply with applicable law or any of Columbia OpCo’s debt or other agreements. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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The amount of cash Columbia OpCo generates from its operations will fluctuate from quarter to quarter based on, among other things:

 

   

the fees it charges and the margins it realizes for its services;

 

   

regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility;

 

   

the level of its operating, maintenance and general and administrative costs; and

 

   

prevailing economic conditions.

In addition, the actual amount of cash Columbia OpCo will have available for distribution to its partners, including us, also will depend on other factors, such as:

 

   

the level of capital expenditures it makes;

 

   

its debt service requirements and other liabilities;

 

   

restrictions contained in its debt agreements, including HoldCo’s new credit facility;

 

   

its ability to borrow funds;

 

   

fluctuations in its working capital needs;

 

   

the cost of acquisitions, if any; and

 

   

the amount of cash reserves established by it.

Our future business opportunities may be limited as a result of our agreement with HoldCo to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that it may enter into with NiSource in connection with the spin-off.

Under the omnibus agreement, we will agree to refrain from taking any action that would prevent HoldCo from complying with the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Under such tax sharing agreement, HoldCo will likely agree to take certain actions, or refrain from taking action, to ensure that the spin-off qualifies for tax-free status under Section 355 of the Internal Revenue Code of 1986, as amended (the “Code”), such as issuing or redeeming common stock or other securities, or permitting its subsidiaries to do so. In compliance with our obligations under the omnibus agreement, we also will agree not to take any action that could cause HoldCo to violate one of the covenants in the tax sharing agreement. For example, subject to certain limited exceptions, HoldCo is expected to agree that, for the two years following the spin-off, HoldCo will not permit CEG to enter into a transaction that would result in CEG no longer owning our general partner or that would result in CEG owning less than 55% of Columbia OpCo. The tax sharing agreement will be executed after the closing of the offering and the execution of the omnibus agreement, and may contain covenants more restrictive on Columbia OpCo than we currently anticipate. As a result, certain of our business opportunities and plans may be restricted or limited, such as our ability to acquire additional interests in Columbia OpCo, our ability to sell the general partner of Columbia OpCo, our ability to direct Columbia OpCo to sell assets outside the ordinary course of business and our ability to direct Columbia OpCo to dispose of business assets relied upon to satisfy the “active trade or business” requirement of Section 355 of the Code for the two-period period following the spin-off, which may adversely impact our financial condition, results of operations and ability to make distributions to you. Please read “Business—Spin-off.”

Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations on a per unit basis.

Even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations on a per unit basis. Any expansion project involves potential risks, including, among other things:

 

   

service interruptions or increased downtime associated with our projects, including the reversal of Columbia Gulf’s pipelines;

 

   

a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the project or acquisition;

 

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an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits, among other factors;

 

   

the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;

 

   

the diversion of our management’s attention from other business concerns;

 

   

mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, including synergies and potential growth;

 

   

an inability to successfully integrate the businesses we build;

 

   

an inability to receive cash flows from a newly built asset until it is operational; and

 

   

unforeseen difficulties operating in new product areas or new geographic areas.

If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per unit, our ability to make distributions to you may be reduced.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to you.

We rely on certain key customers for a significant portion of our revenues. Columbia Gas of Ohio, an affiliated party, and Washington Gas Light Company accounted for approximately 14%, and 9% of our contracted revenues, respectively, for the year ended December 31, 2013. Columbia Gas of Ohio and Washington Gas Light accounted for approximately 12% and 8% of our contracted revenues, respectively, for the nine months ended September 30, 2014. The loss of all or even a portion of the contracted volumes of these or other customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you, unless we are able to contract for comparable volumes from other customers at favorable rates.

The expansion of our existing assets and construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition, and reduce our cash from operations on a per unit basis.

One of the ways we intend to grow our business is through the expansion of our existing assets and construction of new energy infrastructure assets. The construction of additions or modifications to our existing pipelines, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant capital that we may be unable to raise. If we undertake these projects they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. We may also construct facilities to capture anticipated future growth in production or demand in regions such as the Marcellus and Utica shale production areas, which may not materialize or where contracts are later cancelled. Since we are not engaged in the exploration for and development of natural gas reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The construction of new pipelines may also require us to obtain new

 

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rights-of-way, and it may become more expensive for us to obtain these new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus shale play. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

A substantial portion of Columbia OpCo’s organic growth projects are supported by binding precedent agreements that are subject to certain conditions, which, if not satisfied, would permit the customer to opt out of the agreement.

A substantial portion of Columbia OpCo’s $4.9 billion in estimated capital costs for organic growth projects are supported by a combination of (i) service agreements, which are long-term legally binding obligations that secure Columbia OpCo’s revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either Columbia OpCo or the customer to terminate the agreement. These conditions include, among others, the receipt of governmental approvals and the achievement of certain in-service dates. If the conditions in a precedent agreement are not satisfied and the customer elects to terminate the agreement, the underlying project and the related revenue streams could be at risk, which could have a material adverse effect on our financial condition, results of operations and our ability to make distributions to unitholders.

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in response to historically low natural gas prices, a number of large natural gas producers have recently announced their intention to re-evaluate and/or reduce their drilling programs in certain areas. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.

The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

 

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Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves.

A portion of the cash available for distribution to our unitholders is derived from royalty payments we receive on our mineral rights positions through our working interests and overriding royalty interests. We are not the operator of the wells from which we receive royalty payments and therefore, we are not able to control the timing of exploration or development efforts, or associated costs.

Through our subsidiary, CEVCO, we own production rights to over 450,000 acres in the Marcellus and Utica shale areas and have sub-leased the production rights in four storage fields and have also contributed our production rights in one other field. We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:

 

   

the timing and amount of capital expenditures;

 

   

the timing of initiating the drilling and recompleting of wells;

 

   

the extent of operating costs;

 

   

selection of technology and drilling and completion methods; and

 

   

the rate of production of reserves, if any.

If the royalty payments we receive from our sublessees are reduced, our ability to make cash distributions to our unitholders could be adversely affected.

Our revenues from CEVCO royalty interests will decrease if production on our sub-leased production rights declines, which would reduce the amount of cash we have available for distribution to our unitholders.

The amount of the royalty payments we receive on our sub-leased production rights depends in part on the amount of production on our properties. In addition, the royalty payments vary with the natural gas liquids and oil content of the production. For example, “dry gas” wells produce mainly natural gas, or methane, as opposed to “wet gas” wells, which produce methane along with other byproducts such as ethane, which may result in additional revenue streams from such production. During 2013 and 2012, natural gas prices remained relatively low, leading some producers to announce significant reductions to their drilling plans in dry gas areas. A significant reduction in the level of production on our properties could adversely affect on our ability to make distributions to our unitholders. Similarly, increased dry gas production attributable to our royalty interest would generally result in less revenue for us than the production of wet gas (i.e., production that includes oil and natural gas liquids). As a result, any significant decline in production volumes or decrease in wet gas production would reduce our royalty payments, which could adversely affect our ability to make distributions to our unitholders.

 

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Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.

Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade pipelines and other facilities. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; and incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates polychlorinated biphenyls (“PCBs”) at specific gas transmission facilities pursuant to a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs will cease on January 31, 2015. As of September 30, 2014, Columbia Gas Transmission has recorded $2.8 million to cover costs associated with PCB remediation related to this AOC.

Moreover, new, modified or stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our or our customer’s compliance costs, pollution mitigation costs, or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. Our compliance with such new or amended legal requirements could result in our incurring significant additional expense and operating restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers, to whom we provide our services, may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business. For example, a number of state and regional legal initiatives have emerged in recent years that seek to reduce greenhouse gas (“GHG”) emissions and the U.S. Environmental Protection Agency (“EPA”), based on its findings that emissions of greenhouse gases present a danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore processing sources in the U.S. on an annual basis. Such regulations or any new federal laws restricting emissions of GHGs from customer operations could delay or curtail their activities and, in turn, adversely affect our business. In another example, the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing while the U.S. Congress, certain state agencies, and some local governments have from time to time considered or adopted and implemented legal requirements that have imposed, and in the future could continue to impose, new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, which requirements could cause our customers to incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our transportation services.

Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial or compliance obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or

 

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increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. Please read “Business—Environmental and Occupational Health and Safety Regulation” for more information.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair, or preventative or remedial measures.

The United States Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

In addition, the DOT is examining the possibility of expanding integrity management principles beyond high consequence areas.

We have incurred costs of approximately $181 million ($96 million in capital costs and $85 million in expenses) between 2007 and 2013 associated with the assessment of our pipelines to implement the integrity management program. In addition, we currently anticipate we will incur an annual average capital cost of $28 million (and an average annual operating and maintenance cost of $22 million) for the years 2014 through 2016 to implement the program.

There may be additional costs associated with any other major repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. In addition, any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business—Pipeline Safety and Maintenance” for more information.

We may incur significant costs from time to time in order to comply with DOT regulations regarding the design, strength and testing of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.

DOT regulations govern the design strength and testing of our pipelines. The required design strength and testing of the pipe depends upon the population density near the pipeline. In the event the population density around any specific section of our pipelines increases above levels established by the DOT, we may be required to upgrade the section of our pipelines traversing through the area with pipe of higher strength or, in some cases, retest the pipe, unless a waiver from the DOT is obtained. While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur significant expenses in the future in response to increases in population density near sections of our pipelines.

We may incur significant costs and liabilities to comply with new DOT regulations that are anticipated to be issued in the future.

The Natural Gas Pipeline Safety Act (“NGPSA”) was amended on January 3, 2012 when the president signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The DOT issued an advanced notice of proposed rulemaking in August of 2011 that addressed approximately 15

 

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specific topics associated with the legislation. The topics included the role of valves in mitigating consequences, metal loss evaluation and response, pressure testing to address manufacturing and construction threats, expanding integrity management principles, underground storage of natural gas and leak detection systems, among other topics. In addition, the DOT is working on other rulemaking topics such as operator verification of records confirming the maximum allowable operating pressure of certain pipelines and integrity verification of previously untested pipelines or pipelines with other potential integrity issues, as well as others. There may be additional costs and liabilities associated with many of these pending future requirements. We continue to monitor regulatory developments associated with these pending regulations to help anticipate potential future operational and financial risks associated with the implementation of any new regulations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and Hazardous Liquid Pipeline Safety Act pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of Pipeline Hazardous Materials Safety Administration (“PHMSA”) rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our natural gas transportation and storage operations are subject to extensive regulation by the FERC.

Our business operations are subject to extensive regulation by the FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. Compliance with these requirements can be costly and burdensome and the FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC’s regulations. We cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation and storage business or the effect such regulation could have on our business, financial condition and results of operations.

Rate regulation could limit our ability to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.

The rates we can charge for our natural gas transportation and storage operations are regulated by the FERC pursuant to the Natural Gas Act of 1938 (“NGA”). Under the NGA, we may only charge rates that have been

 

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determined to be just and reasonable by the FERC and are prohibited from unduly preferring or unreasonably discriminating against any person with respect to our rates or terms and conditions of service. The FERC establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the volumes of gas being transported or stored, the rate design, the allocation of costs between services, the capital structure and the rate of return a natural gas company is permitted to earn.

We may not be able to recover all of our costs through existing or future rates. Proposed rate increases may be challenged by protest and allowed to go into effect subject to refund. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected.

Our existing rates may be challenged by complaint or sua sponte by the FERC. In recent years, the FERC has exercised this authority with respect to several other pipeline companies. In a potential proceeding involving the challenge of our existing rates, the FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. Any successful challenge against our rates could have an adverse impact on our revenues associated with providing transportation and storage services. In addition, future changes to laws, regulations and policies may impair our ability to recover costs and the ability to make distributions to you.

Certain of our gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as result of these “negotiated rate” contracts could decrease our cash flow.

We are exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements. The FERC-approved tariffs of our transmission and storage companies provide for annual filings to adjust the amount of gas retained from customers to eliminate any overages or shortfalls from the prior year. Our gathering companies have contracts that provide for specified levels of fuel retainage, so they may find it necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our gathering systems could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

We could be subject to penalties and fines if we fail to comply with FERC regulations.

Should the FERC find that we have failed to comply with all applicable FERC-administered statutes, rules, regulations, and orders, or the terms of our tariffs on file with the FERC, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005 (“EPAct 2005”), the FERC has civil penalty authority under the NGA and Natural Gas Policy Act of 1978 (“NGPA”) to impose penalties for violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

 

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Certain of our assets may become subject to FERC regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of substantial litigation and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If more of our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

We do not own all of the land on which our pipelines are located, which could disrupt our operations.

We do not own all of the land on which our pipelines are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights required to conduct our operations. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. In certain instances, our rights-of-way may be subordinate to that of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.

Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.

Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:

 

   

aging infrastructure, mechanical or other performance problems;

 

   

damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

 

   

inadvertent damage from third parties, including from construction, farm and utility equipment;

 

   

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

 

   

operator error;

 

   

environmental hazards, such as natural gas leaks, product and waste spills, pipeline and tank ruptures, and unauthorized discharges of products, wastes and other pollutants into the surface and subsurface environment, resulting in environmental pollution; and

 

   

explosions and blowouts.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations or services. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.

We have entered into a new $500 million credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility. Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement initially with NiSource Finance, and following the spin-off, with HoldCo with $750 million of reserved borrowing

 

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capacity, which will be undrawn at the time of closing. In addition, Columbia OpCo, CEG and OpCo GP will guarantee HoldCo’s credit facility as well as future HoldCo indebtedness if requested. Our existing and future level of debt, as well as Columbia OpCo’s future level of debt, could have important consequences to us, including the following:

 

   

our ability and Columbia OpCo’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

 

   

the funds that we or Columbia OpCo have available for operations and cash distributions to unitholders will be reduced by that portion of our and Columbia OpCo’s respective cash flow required to make principal and interest payments on outstanding debt; and

 

   

our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt and Columbia OpCo’s debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Restrictions in our new or any future credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the value of our common units.

We have entered into a new credit facility, which will become effective at the closing of this offering. Our new credit facility, or any future credit facility we or Columbia OpCo may enter into, is likely to limit our ability and Columbia OpCo’s ability to, among other things:

 

   

make distributions if any default or event of default occurs;

 

   

make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

   

grant liens or make certain negative pledges;

 

   

make certain loans or investments;

 

   

engage in transactions with affiliates;

 

   

transfer, sell or otherwise dispose of all or substantially all of our or Columbia OpCo’s assets; or

 

   

enter into a merger, consolidate, liquidate, wind up or dissolve.

Furthermore, any new or future credit facility may also contain covenants requiring us or Columbia OpCo to maintain certain financial ratios and tests. Our ability and Columbia OpCo’s ability to comply with the covenants and restrictions contained in our credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability and Columbia OpCo’s ability to comply with these covenants may be impaired. If we or Columbia OpCo violates any of the restrictions, covenants, ratios or tests in our credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, our lenders’ commitment to make further loans to us may terminate and Columbia OpCo will be prohibited from making any distribution to us and, ultimately, to you. We might not have, or be able to obtain, sufficient funds to

 

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make these accelerated payments. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.

The credit and risk profiles of our general partner and its ultimate owner, NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo debt, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of our general partner and NiSource, and, following the spin-off, HoldCo, or Columbia OpCo’s guarantee of HoldCo debt, may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of NiSource, and, following the spin-off, HoldCo, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.

If we seek a credit rating in the future, our credit rating may be adversely affected by our guarantee of HoldCo debt and the leverage of our general partner or NiSource, and, following the spin-off, HoldCo, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of NiSource, and, following the spin-off, HoldCo, and their respective affiliates because of their ownership interest in and control of us and the strong operational links between NiSource, and, following the spin-off, HoldCo, and us. Any adverse effect on our credit rating could increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could impair our ability to grow our business and make distributions to unitholders.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available for distribution could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines. For example, our pipelines interconnect with virtually every major interstate pipeline in the eastern portion of the U.S. and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections were to become unavailable for current or future volumes of natural gas due to repairs, damage, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect which causes a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to you.

The current Columbia Gulf and Columbia Gas Transmission pipeline infrastructure is aging, which may adversely affect our business, results of operations, financial condition and ability to make distributions.

The Columbia Gulf and Columbia Gas Transmission pipeline systems have been in operation for many years, with some portions of these pipelines being more than 50 years old. Segments of the Columbia Gulf and Columbia Gas Transmission pipeline systems are located in or near areas determined to be high consequence areas. We implement integrity management testing of the pipelines that we operate, including the Columbia Gulf and Columbia Gas Transmission pipelines, and we repair, remediate or replace segments on those pipelines as necessary when anomaly conditions are identified during the integrity testing process or are determined to have occurred during the course of operations. Nonetheless, we also are currently investing significant capital over the next several years to replace aging infrastructure, including replacement of the relatively older pipe found on the Columbia Gulf and Columbia Gas Transmission systems. If, due to their age, these pipeline sections were to become unexpectedly unavailable for current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could result in a material adverse impact on our business, financial condition and results of operation as well as our ability to make distributions to our unitholders.

 

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LNG export terminals may not be developed in the Gulf Coast region or may be developed outside our areas of operations.

We are in the process of reversing the flow of the Columbia Gulf pipeline system in order to supply new and developing LNG export facilities located along the Gulf Coast. However, we may not realize expected increases in future natural gas demand from LNG exports due to factors including:

 

   

new projects may fail to be developed;

 

   

new projects may not be developed at their announced capacity;

 

   

development of new projects may be significantly delayed;

 

   

new projects may be built in locations that are not connected to our system; or

 

   

new projects may not influence sources of supply on our system.

Similarly, the development of new, or the expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas on our assets. This could reduce the amount of natural gas transported by our pipeline.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them and inability to re-market the resulting capacity could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. We may not be able to effectively re-market such capacity during and after insolvency proceedings involving a customer.

If we are unable to make acquisitions from our sponsor or third parties on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions of additional interests in Columbia OpCo from CEG on acceptable terms, or we are unable to obtain financing for these acquisitions on economically acceptable terms, our future growth and ability to increase distributions will be limited. In addition, we may be unable to make acquisitions from third parties as an alternative avenue to growth. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

 

   

mistaken assumptions about revenues and costs, including synergies;

 

   

the inability to successfully integrate the businesses we acquire;

 

   

the inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

mistaken assumptions about the overall costs of equity or debt;

 

   

the diversion of management’s attention from other business concerns;

 

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unforeseen difficulties in connection with operating in new product areas or new geographic areas; and

 

   

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the U.S., whether or not targeted at our assets or the assets of our customers, could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from customers or disruptions of fuel supplies and markets if domestic and global utilities are direct targets or indirect casualties of an act of terror or war. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

A failure in Columbia OpCo’s computer systems or a cyber-attack on any of its facilities or any third parties’ facilities upon which Columbia OpCo relies may adversely affect its ability to operate.

Columbia OpCo relies on technology to run its businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of its business, including the generation, transmission and distribution of electricity, operation of its gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of Columbia OpCo’s computer systems, or those of its customers, suppliers or others with whom it does business, could materially disrupt Columbia OpCo’s ability to operate its businesses and could result in a financial loss and possibly do harm to Columbia OpCo’s reputation.

Additionally, Columbia OpCo’s information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach Columbia OpCo’s cyber-defenses. Although Columbia OpCo attempts to maintain adequate defenses to these attacks and works through industry groups and trade associations to identify common threats and assess Columbia OpCo’s countermeasures, a security breach of Columbia OpCo’s information systems could (i) impact the reliability of Columbia OpCo’s transmission and storage systems and potentially negatively impact Columbia OpCo’s compliance with certain mandatory reliability standards, (ii) subject Columbia OpCo to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to Columbia OpCo’s customers or employees or (iii) impact Columbia OpCo’s ability to manage its businesses.

Sustained extreme weather conditions and climate change may negatively impact Columbia OpCo’s operations.

Columbia OpCo conducts its operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather related stress on Columbia OpCo’s infrastructure may reveal weaknesses in its systems not previously known to it or otherwise present various operational challenges across all business segments. Although Columbia OpCo makes every effort to plan for weather related contingencies, adverse weather may affect its ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. Columbia OpCo endeavors to minimize such service disruptions, but may not be able to avoid them altogether.

There is also a concern that climate change may exacerbate the risks to physical infrastructure arising from significant physical effects, such as increased severity and frequency of storms, droughts and floods as well as

 

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associated with heat and other extreme weather conditions. Climate change and the costs that may be associated with its impacts have the potential to affect Columbia OpCo’s business in many ways, including increasing the cost Columbia OpCo incurs in providing its products and services, impacting the demand for and consumption of its products and services (due to change in both costs and weather patterns), and affecting the economic health of the regions in which Columbia OpCo operates.

Growing competition in the gas transportation and storage industries could result in the failure by customers to renew existing contracts.

As a consequence of the increase in competition and the shift in natural gas production areas, customers such as LDCs and other end users may be reluctant to enter into long-term service contracts. The renewal or replacement of existing contracts with Columbia OpCo’s customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. The inability of Columbia OpCo to renew or replace its current contracts as they expire and respond appropriately to changing market conditions could materially impact its financial results and cash flows.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse impact on Columbia OpCo’s operations.

Our business is dependent on CEG’s and our general partner’s ability to attract, retain and motivate employees. Competition for skilled employees in some areas is high and CEG and our general partner may experience difficulty in recruiting and retaining employees in light of the proposed spin-off. The inability to recruit and retain these employees could adversely affect our business and future operating results. CEG seeks to mitigate some of this risk by training its management on how to attract and select the needed talent and also measures its level of employee engagement annually, developing action plans where necessary to improve CEG’s workplace, but there is no assurance that such mitigation measures will be effective.

Columbia OpCo’s insurance policies do not cover all losses, costs or liabilities that it may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Columbia OpCo’s assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. All of the insurance policies relating to Columbia OpCo’s assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies ranges from 30 to 45 days. Columbia OpCo does not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and Columbia OpCo may elect to self-insure portions of its asset portfolio. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on Columbia OpCo’s business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums to cover Columbia OpCo’s assets and operations. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, Columbia OpCo may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of full insurance coverage to cover events in which Columbia OpCo suffers significant losses could have a material adverse effect on our business, financial condition and results of operation, and therefore on our ability to pay cash distributions.

 

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Risks Inherent in an Investment in Us

Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

Following the offering, our sponsor will own and control our general partner and will appoint all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our sponsor. Therefore, conflicts of interest may arise between our sponsor or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

 

   

our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement;

 

   

neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us;

 

   

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duties;

 

   

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

   

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

   

our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Please read “How We Make Distributions to Our Partners—Capital Expenditures” for a discussion of when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert into common units. Please read “How We Make Distributions to Our Partners—Subordination Period”;

 

   

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

 

   

in determining whether to request a guarantee from Columbia OpCo, HoldCo may elect to act in a manner that protects HoldCo’s credit rating or credit availability to our detriment or to the detriment of Columbia OpCo, or may take actions that increase the risk that HoldCo would default on its debt obligations and therefore increase the likelihood that the Columbia OpCo guarantee would be called on.

 

   

our partnership agreement permits us to distribute up to $62 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

 

   

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

 

   

our general partner intends to limit its liability regarding our contractual and other obligations;

 

   

our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

   

our general partner controls the enforcement of obligations that it and its affiliates owe to us;

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

   

CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to CEG’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, we may compete directly with our sponsor and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read “—Our sponsor and other affiliates of our general partner may compete with us” and “Conflicts of Interest and Fiduciary Duties.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.1675 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

 

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We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional common units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

If you are not an Eligible Holder, your common units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are limited partners or types of limited partners (a) whose, or whose owners’, U.S. federal income tax status does not, in the determination of our general partner, create or is not reasonably likely to create substantial risk of an adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel or (b) whose nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Ineligible Holders; Redemption.”

Our partnership agreement replaces our general partner’s fiduciary duties to us and holders of our units.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its call right;

 

   

how to exercise its voting rights with respect to the units it owns;

 

   

whether to exercise its registration rights;

 

   

whether to elect to reset target distribution levels; and

 

   

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

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Our partnership agreement restricts the remedies available to us and holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, not in bad faith, meaning that they did not believe that the decision was adverse to the interest of the partnership and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

   

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership, or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

   

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

 

  (1) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

 

  (2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must not be made in bad faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

Our sponsor and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our sponsor. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such

 

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opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

CEG has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters and the aggregate amount of cash distributions during such four-quarter period does exceed adjusted operating surplus generated during such four-quarter period, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If CEG elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to CEG will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election. We anticipate that CEG would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that CEG could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights are transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. CEG may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels. Please read “How We Make Distributions to Our Partners—IDR Holders’ Right to Reset Incentive Distribution Levels.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim

 

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arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a unitholder is irrevocably consenting to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement and the potential obligation to reimburse us for all fees, costs and expenses incurred in connection with claims, suits, actions or proceedings initiated by a unitholder that are not successful, please read “The Partnership Agreement—Applicable Law; Forum, Venue and Exclusive Jurisdiction; Reimbursement of Litigation Costs.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our sponsor, as a result of it owning our general partner, and not by our unitholders. Please read “Management—Management of Columbia Pipeline Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, our sponsor will own an aggregate of 57.3% of our common and subordinated units (or 53.8% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner.

Unitholders will experience immediate and substantial dilution of $11.86 per common unit.

The assumed initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $8.14 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, unitholders will incur immediate and substantial dilution of $11.86 per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

 

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Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

The incentive distribution rights may be transferred to a third party without unitholder consent.

CEG may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If CEG transfers the incentive distribution rights to a third party, CEG would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by CEG could reduce the likelihood of it accepting offers made by us relating to assets owned by CEG, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Upon completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, our sponsor will own an aggregate of 57.3% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our sponsor will own 57.3% of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash available for distribution on each unit may decrease;

 

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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding unit may be diminished; and

 

   

the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our sponsor or other large holders.

After this offering, we will have 46,811,398 common units and 46,811,398 subordinated units outstanding, which includes the 40,000,000 common units we are selling in this offering that may be resold immediately in the public market. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. All of the 6,811,398 common units that are issued to our sponsor will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by our sponsor or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our sponsor. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Please read “Units Eligible for Future Sale.”

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

 

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Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only 40,000,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

   

general economic conditions;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

   

future sales of our common units; and

 

   

the other factors described in these “Risk Factors.”

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency

 

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were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have applied to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly,

 

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unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Columbia Pipeline Partners LP.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership, will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the board of directors of our general partner or as executive officers.

We estimate that we will incur approximately $5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you

 

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would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

 

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Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, and for other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and

 

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deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, CEG will indirectly own 57.3% of the total interests in our capital and profits. Therefore, a transfer by CEG of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that

 

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includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in several states, each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $755.0 million from this offering (based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount, the structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and offering expenses, to purchase an additional approximate 6.2% limited partner interest in Columbia OpCo. The approximate 6.2% interest in Columbia OpCo purchased with the proceeds from this offering, when combined with an approximate 8.4% interest in Columbia OpCo contributed to us in connection with the formation transactions, will result in our ownership of a 14.6% limited partner interest in Columbia OpCo following the closing of the offering.

Columbia OpCo will use $500.0 million of the net proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures. We would expect the remaining net proceeds of $255.0 million to be completely utilized during the twelve months ended December 31, 2015, for these purposes.

If the underwriters exercise their option to purchase 6,000,000 additional common units in full, the additional net proceeds would be approximately $114.0 million (based upon the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to purchase an additional percentage limited partner interest in Columbia OpCo, and Columbia OpCo will use such cash to fund growth projects and for general partnership purposes. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% additional limited partner interest in Columbia OpCo purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo and our total ownership interest in Columbia OpCo would be 15.6%.

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discount, structuring fee and offering expenses payable by us, to increase or decrease, respectively, by approximately $38.0 million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed public offering price to $21.00 per common unit, would increase net proceeds to us from this offering by approximately $57.9 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed initial offering price to $19.00 per common unit, would decrease the net proceeds to us from this offering by approximately $56.1 million. If we increase or decrease the number of common units offered, we will proportionately increase or decrease, respectively, the percentage interest in Columbia OpCo which we will purchase with the net proceeds of this offering. Columbia OpCo may concomitantly increase or reduce, as applicable, the amount of CEG reimbursement for capital expenditures. As a result, cash available for distribution per unit is expected to remain unchanged regardless of the changes in the number of common units offered.

 

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CAPITALIZATION

The following table shows our capitalization as of September 30, 2014:

 

   

on a historical basis for the Predecessor;

 

   

on a historical basis for the Predecessor, as adjusted to reflect the removal of amounts related to Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company that were included in the Predecessor but are not being contributed to the Partnership, as well as the inclusion of CNS Microwave, Inc., which was not part of the Predecessor; and

 

   

on a pro forma basis to reflect the offering of our common units, the other transactions described under “Summary—Formation Transactions and Partnership Structure” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Summary—Formation Transactions and Partnership Structure,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

    As of September 30, 2014  
    Predecessor
Historical
    Predecessor
Historical,

 As  Adjusted 
    Pro Forma  
    (in millions)  

Cash and cash equivalents

  $ 0.4      $ 0.3      $ 255.3   
 

 

 

   

 

 

   

 

 

 

Long-term debt—affiliated

  $ 1,370.9      $ 1,370.9      $ 511.6   

Parent net investment/partners’ net equity

     

Net parent investment

    4,122.3        4,113.0        —     

Accumulated other comprehensive loss

    (16.9     (17.0     —     

Common units—public(1)

    —          —          650.1   

Common units—CEG(1)

    —          —          50.8   

Subordinated units—CEG(1)

    —          —          349.4   

Noncontrolling interest(1)(2)

    —          —          5,643.4   

Total parent net investment/partners’ net equity

    4,105.4        4,096.0        6,693.7   
 

 

 

   

 

 

   

 

 

 

Total capitalization

  $ 5,476.3      $ 5,466.9      $ 7,205.3   
 

 

 

   

 

 

   

 

 

 

 

(1) 

Pro forma amounts reflect the capital attributable to our limited and general partners. Pro forma partners’ net equity reflects an increase of $1,127.9 million to eliminate certain historical current and deferred income taxes that will not be borne by the Partnership and an increase of $1,214.8 million for the assumption of debt by CEG. Pro forma partners’ net equity also assumes offering proceeds of $755.0 million, net of the underwriting discount, structuring fee and other expenses of the initial public offering of $36.0 million, $4.0 million and $5.0 million, respectively, all of which were allocated to the public common units. Pro forma partners’ net equity further reflects an increase of $540.9 million for the initial contribution from CEG for an approximate 8.4% interest in Columbia OpCo. Pro forma partners’ net equity also includes an adjustment of $245.6 million to the limited partner equity accounts for the excess of consideration paid by us to purchase our additional limited partner interest in Columbia OpCo with net proceeds from this offering over the historical carrying value of the additional interest. Pro forma partners’ net equity also gives effect to a $500.0 million decrease in the Noncontrolling interest of Columbia OpCo for the distribution to CEG for the reimbursement of preformation capital expenditures.

(2) 

Reflects the noncontrolling interest held by CEG in Columbia OpCo.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Assuming an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus), on a pro forma basis as of September 30, 2014, after giving effect to the offering of common units and the related transactions, our net tangible book value would have been approximately $761.9 million, or $8.14 per common unit. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit

     $ 20.00   

Predecessor historical as adjusted net tangible book value per common unit before the offering(1)

   $ 6.99     

Increase in net tangible book value per common unit attributable to the offering(2)

   $ 3.77     

Decrease in net tangible book value per common unit attributable to the excess of the consideration paid by us to purchase our additional limited partner interest in Columbia OpCo with the net proceeds from this offering over the historical carrying value of the additional interest acquired in Columbia OpCo’s net assets(3)

   $ (2.62  

Less: Pro forma net tangible book value per common unit after the offering(4)

     $ 8.14   
    

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(5)(6)

     $ 11.86   
    

 

 

 

 

(1) 

Determined by dividing the Predecessor historical as adjusted net tangible book value of the 8.4% limited partner interest in Columbia OpCo ($375.0 million) by the number of units (6,811,398 common units and 46,811,398 subordinated units) to be issued prior to the offering to CEG for its contribution of the 8.4% limited partner interest in Columbia OpCo to us. The Predecessor historical as adjusted net tangible book value of $375.0 million is determined by subtracting (A) $165.9 million (an 8.4% interest in the Predecessor’s $1,975.5 million of goodwill) from (B) $540.9 million (the book value of the 8.4% limited partner interest in Columbia OpCo that CEG contributes to the Partnership). For more information regarding the calculation of book value, please refer to Note 2(i) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(2) 

Determined by adding the (A) pro forma net tangible book value per common unit after the offering ($8.14) to the (B) decrease in net tangible book value per common unit attributable to the excess consideration ($2.62) and subtracting (C) the Predecessor historical as adjusted net tangible book value per common unit before the offering ($6.99).

(3) 

Determined by dividing (A) the excess consideration paid by us to purchase the additional interest in Columbia OpCo of $245.6 million by (B) the total number of units outstanding after the offering (46,811,398 common units and 46,811,398 subordinated units). For more information regarding the calculation of the excess consideration, please refer to Note 2(l) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(4) 

Determined by dividing our pro forma net tangible book value of $761.9 million, after giving effect to the use of proceeds of the offering, by the total number of units outstanding after the offering (46,811,398 common units and 46,811,398 subordinated units). The Partnership’s pro forma net tangible book value of $761.9 million is determined by subtracting (A) $288.4 million (a 14.6% interest in the Predecessor’s $1,975.5 million of goodwill) from (B) $1,050.3 million (the Partnership’s net book value after the offering). For more information regarding the calculation of book value, please refer to Note 2(l) in the Notes to Unaudited Pro Forma Combined Financial Statements.

(5) 

Each $1.00 increase or decrease in the assumed public offering price of $20.00 per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $38.0 million, or approximately $0.41 per common unit, and dilution per common unit to investors in this offering by approximately $0.59 per common unit, after deducting the estimated underwriting discount, structuring fee

 

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  and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. An increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed offering price to $21.00 per common unit, would result in a pro forma net tangible book value of approximately $819.2 million, or $8.75 per common unit, and dilution per common unit to investors in this offering would be $12.25 per common unit. Similarly, a decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed public offering price to $19.00 per common unit, would result in an pro forma net tangible book value of approximately $705.0 million, or $7.53 per common unit, and dilution per common unit to investors in this offering would be $11.47 per common unit. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
(6) 

Assumes no exercise of the underwriters’ option to purchase additional common units from us. After giving effect to the full exercise of the underwriters’ option to purchase 6,000,000 additional common units from us, the pro forma net tangible book value per common unit after the offering would be $9.28, resulting in an immediate dilution in net tangible book value to purchasers in the offering of $10.72 per common unit.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our sponsor and by the purchasers of our common units in this offering upon completion of the transactions contemplated by this prospectus.

 

     Units     Total Consideration  
     Number      Percent     Amount      Percent  
                  (in millions)         

CEG(1)(2)(3)

     53,622,796         57.3   $ 40.9         4.9

Purchasers in the offering(4)

     40,000,000         42.7   $ 800.0         95.1
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     93,622,796         100   $ 840.9         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Upon the completion of the transactions contemplated by this prospectus, CEG will own 6,811,398 common units and all 46,811,398 of our subordinated units.

(2) 

The assets contributed by CEG will be recorded at historical cost. The pro forma book value of the consideration provided by CEG as of September 30, 2014 would have been approximately $540.9 million.

(3)

Book value of the consideration provided by CEG, as of September 30, 2014, after giving effect to the net proceeds of the offering is as follows (in millions):

 

CEG’s initial contribution to us of certain limited partner interests and all of the general partner interests in Columbia OpCo(i)

   $ 540.9   

Less:

  

Distribution to CEG as a reimbursement of preformation capital expenditures(ii)

     (500.0
  

 

 

 

Total consideration

   $ 40.9   
  

 

 

 

 

  (i) Represents our proportionate limited partner interests in the historical carrying value of Columbia OpCo’s net assets prior to this offering.
  (ii) The distribution to CEG will be made from Columbia OpCo to CEG. This distribution will not impact the controlling interest equity of the Partnership.

 

(4) 

Assumes the underwriters’ option to purchase additional common units is not exercised.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, you should refer to Columbia Pipeline Partners LP Predecessor’s audited historical financial statements as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 and to Columbia Pipeline Partners LP Predecessor’s unaudited financial statements as of and for the nine months ended September 30, 2014 and our unaudited pro forma combined financial statements for the year ended December 31, 2013 and as of and for the nine months ended September 30, 2014, included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.1675 per unit ($0.67 per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. Our general partner has not established any cash reserves, and does not have any specific types of expenses for which it intends to establish reserves. We expect our general partner may establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution.

The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay quarterly distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter, and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

   

Our cash flow initially will depend completely on Columbia OpCo’s distributions to us as one of its partners.

 

   

The amount of cash Columbia OpCo can distribute to its partners will depend upon the amount of cash it generates from operations less any reserves that may be appropriate for operating its business. Columbia OpCo’s ability to make cash distributions to us may be subject to restrictions on distributions under our credit facility and HoldCo’s credit facility, both of which Columbia OpCo will guarantee and may be subject to restrictions in any future HoldCo indebtedness that Columbia OpCo guarantees. If HoldCo were to default under future indebtedness, Columbia OpCo would be unable to make

 

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distributions to us. Please read “Risk Factors—Risks Inherent in Our Business—Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.”

 

   

Because we control Columbia OpCo’s general partner, we have the authority to determine the amount of Columbia OpCo’s distributions, including the amount of cash reserved by Columbia OpCo and not distributed. We have a duty to make decisions with respect to Columbia OpCo in the best interest of all of its partners, including CEG. Our decision to make distributions, if any, and the amount of those distributions, if any, could result in a reduction in cash distributions to our unitholders from levels we currently anticipate pursuant to our stated distribution policy.

 

   

Our cash distribution policy may be subject to restrictions on cash distributions under our new credit facility and any future debt agreements. Such restrictions may prohibit us from making cash distributions while an event of default has occurred and is continuing under our new credit facility, notwithstanding our cash distribution policy.

 

   

We expect to establish reserves for the prudent conduct of Columbia OpCo’s business (including reserves for working capital, maintenance capital expenditures, environmental matters, legal proceedings and other operating purposes). Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.

 

   

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.

 

   

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

 

   

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating expenses or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

 

   

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

 

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Our Ability to Grow may be Dependent on Our Ability to Access External Expansion Capital

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will rely primarily upon external financing sources, including borrowings from HoldCo, bank borrowings and issuances of debt and equity securities, to fund our expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our current cash distribution policy will significantly impair our ability to grow. Our new credit facility will limit, and any future debt agreements may limit, our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Inherent in Our Business—Restrictions in our new or any future credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt to finance our growth strategy, we will have increased interest expense, which will in turn reduce the operating surplus that we have to distribute to our unitholders. Please read “Risk Factors—Risks Inherent in Our Business—Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.1675 per unit for each whole quarter, or $0.67 per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $15.7 million per quarter, or $62.7 million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units):

 

     No exercise of option to purchase
additional common units
     Full exercise of option to purchase
additional common units
 
     Aggregate minimum quarterly
distributions
     Aggregate minimum quarterly
distributions
 
     Number of
Units
     One
Quarter
     Annualized      Number of
Units
     One
Quarter
     Annualized  

Publicly held common units

     40,000,000       $ 6,700,000       $ 26,800,000         46,000,000       $ 7,705,000       $ 30,820,000   

Common units held by CEG

     6,811,398         1,140,909         4,563,636         6,811,398         1,140,909         4,563,636   

Subordinated units held by CEG

     46,811,398         7,840,909         31,363,636         46,811,398         7,840,909         31,363,636   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     93,622,796       $ 15,681,818       $ 62,727,272         99,622,796       $ 16,686,818       $ 66,747,272   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Our general partner will initially own a non-economic general partner interest in us, which will not entitle it to receive cash distributions. CEG will hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.192625 per unit per quarter.

 

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We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month in which such distributions are made. We will adjust the quarterly distribution for the period after the closing of this offering through March 31, 2015, based on the actual length of the period.

Subordinated Units

Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014

If we had completed the transactions described under “Summary—Formation Transactions and Partnership Structure” on January 1, 2013, our pro forma cash available for distribution for the year ended December 31, 2013 would have been approximately $50.8 million. This amount would have been sufficient to pay the full minimum quarterly distribution on all of our common units and insufficient to pay the minimum quarterly distribution on our subordinated units for the year ended December 31, 2013 by approximately $11.9 million.

If we had completed the transactions described under “Summary—Formation Transactions and Partnership Structure” on October 1, 2013, our pro forma cash available for distribution for the twelve months ended September 30, 2014 would have been approximately $55.6 million. This amount would have been sufficient to pay the full minimum quarterly distribution on all of our common units and insufficient to pay the minimum quarterly distribution on our subordinated units for the twelve months ended September 30, 2014 by approximately $7.1 million.

The unaudited pro forma combined financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the date indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed in an earlier period.

Following the completion of this offering, we estimate that we will incur $5 million of incremental annual general and administrative expenses as a result of operating as a publicly traded partnership. These incremental general and administrative expenses are not reflected in our unaudited pro forma combined financial statements and consist of expenses such as those associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

 

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Our unaudited pro forma combined financial statements are derived from the audited and unaudited historical financial statements of the Predecessor, included elsewhere in this prospectus. Our unaudited pro forma combined financial statements should be read together with “Selected Historical and Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited and unaudited historical financial statements of the Predecessor and the notes to those statements included elsewhere in this prospectus.

The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended September 30, 2014, the amount of cash that would have been available for distribution to our unitholders, assuming that the transactions described under “Summary—Formation Transactions and Partnership Structure” had been consummated on the beginning of such period. Certain of the adjustments reflected or presented below are explained in the footnotes to such adjustments. Certain components may not add or subtract to totals due to rounding.

Columbia Pipeline Partners LP

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2013
    Twelve  Months
Ended

September 30, 2014
 
     (in millions)  

Operating revenues(1)

   $ 1,176.7      $ 1,326.7  

Operating expenses:

    

Operation and maintenance

     481.4        588.1  

Operation and maintenance—affiliated(2)

     142.5        153.4  

Depreciation and amortization

     106.1        115.0  

Gain on sale of assets(3)

     (18.6     (28.1 )

Property and other taxes

     61.9        65.6  
  

 

 

   

 

 

 

Total operating expenses

     773.3        894.0   
  

 

 

   

 

 

 

Equity earnings in unconsolidated affiliates(4)

     35.8        43.1   
  

 

 

   

 

 

 

Operating income

     439.2        475.8   
  

 

 

   

 

 

 

Interest expense—affiliated(5)

     (1.8     (6.1

Other, net(6)

     22.6        10.6   

Income taxes(7)

     (0.2     (0.2
  

 

 

   

 

 

 

Net income

     459.8        480.1   
  

 

 

   

 

 

 

Add:

    

Interest expense—affiliated(5)

     1.8        6.1   

Income taxes(7)

     0.2        0.2   

Depreciation and amortization

     106.1        115.0   

Cash distributions from unconsolidated affiliates

     32.1        40.7   

Less:

    

Other, net(6)

     22.6        10.6   

Equity earnings in unconsolidated affiliates(4)

     35.8        43.1   
  

 

 

   

 

 

 

Adjusted EBITDA

     541.6        588.4   
  

 

 

   

 

 

 

Less:

    

Cash interest, net(8)

     15.7        20.2   

Maintenance capital expenditures(9)

     131.7        141.1   

Expansion capital expenditures(10)

     658.9        715.8   

Add:

    

Borrowings from affiliates of CEG to fund expansion capital expenditures

     658.9        715.8   

Estimated cash available for distribution by Columbia OpCo

   $ 394.2      $ 427.1   
  

 

 

   

 

 

 

 

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     Year Ended
December 31, 2013
    Twelve  Months
Ended

September 30, 2014
 
     (in millions except per unit amount)  

Less:

    

Estimated cash available for distribution attributable to non-controlling interest in Columbia OpCo(11)

     336.6        364.7   

Cash interest(12)

     1.8        1.8  

Incremental general and administrative expenses(13)

     5.0        5.0   

Estimated cash available for distribution by Columbia Pipeline Partners LP

   $ 50.8      $ 55.6   
  

 

 

   

 

 

 

Minimum annual distribution per unit (based on a minimum quarterly distribution rate of $0.1675 per unit)

   $ 0.6700      $ 0.6700   

Cash distributions

    

Distributions to public common unitholders

   $ 26.8      $ 26.8   

Distributions to CEG:

    

Common units

     4.5        4.5   

Subordinated units

     31.4        31.4   
  

 

 

   

 

 

 

Total distributions to CEG

   $ 35.9      $ 35.9   
  

 

 

   

 

 

 

Total distributions to our unitholders at minimum rate

   $ 62.7      $ 62.7   

Shortfall($)

   $ (11.9   $ (7.1

% of Distributions to Subordinated Units that can be paid

     62.0     77.3

Subordinated Unit Distribution ($/Unit)

   $ 0.42      $ 0.52   

 

(1) 

Operating revenues include affiliate transactions with subsidiaries of CEG that total $148.2 million and $149.0 million for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

(2) 

Represents executive, financial, legal, information technology and other administrative and general services received from an affiliate, NiSource Corporate Services. For more information, please refer to Note 3 “Transactions with Affiliates” in the audited Notes to Combined Financial Statements.

(3) 

Includes approximately $11.1 million in proceeds from sale of base gas and $7.3 million attributable to the conveyance of mineral rights leases for the year ended December 31, 2013 and approximately $28.1 million attributable to the conveyance of mineral rights leases for the twelve months ended September 30, 2014.

(4) 

Represents equity earnings from equity method investments in Millennium Pipeline, Hardy Storage and Pennant. For more information, please refer to Note 9 “Equity Method Investments” in the audited Notes to Combined Financial Statements.

(5) 

Interest expense—affiliated includes interest expense incurred by our Predecessor and the amortization of origination fees incurred in connection with our new revolving credit facility.

(6) 

Consists of a gain from insurance proceeds and AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation. Refer to Note 2(f) “Pro Forma Adjustments and Assumptions,” in the Notes to Unaudited Pro Forma Combined Financial Statements for additional information.

(7) 

Consists of Tennessee state income taxes.

(8) 

Cash interest, net includes interest expense based on historical rates incurred by Columbia OpCo on borrowings from affiliates of CEG to fund expansion capital expenditures.

(9) 

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

(10) 

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the construction, development or acquisition of additional pipeline, storage or gathering capacity, as well as the Columbia Gas Transmission modernization program, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.

 

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(11) 

Represents CEG’s 85.4% limited partner interest in Columbia OpCo.

(12) 

Cash interest includes commitment fees of $1.5 million and the amortization of origination fees of $0.3 million incurred in connection with our new revolving credit facility.

(13) 

Reflects an adjustment for approximately $5.0 million of expenses that we expect to incur as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015

Set forth below is a statement of Estimated Cash Available for Distribution that reflects a forecast of our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the twelve months ending December 31, 2015, based on assumptions we believe to be reasonable. These assumptions include adjustments giving effect to this offering.

Our estimated cash available for distribution for the twelve months ending December 31, 2015 is projected to be $69.0 million, as compared to our pro forma cash available for distribution of $50.8 million for the year ended December 31, 2013 and $55.6 million for the twelve months ended September 30, 2014. Our estimated cash available for distribution reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2015. The assumptions disclosed under “—Assumptions and Considerations” below are those that we believe are significant to our ability to generate such estimated cash available for distribution. We believe our actual results of operations and cash flows for the twelve months ending December 31, 2015 will be sufficient to generate our estimated cash available for distribution for such period; however, we can give you no assurance that such estimated cash available for distribution will be achieved. There will likely be differences between our estimated cash available for distribution for the twelve months ending December 31, 2015 and our actual results for such period and those differences could be material. If we fail to generate the estimated cash available for distribution for the twelve months ending December 31, 2015, we may not be able to pay cash distributions on our common units at the minimum quarterly distribution rate or at any rate.

We do not as a matter of course make public projections as to future sales, earnings, or other results. However, our management has prepared the prospective financial information set forth below to substantiate our belief that we will have sufficient cash available to make the minimum quarterly distribution to our unitholders for the twelve months ending December 31, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability. They assume no responsibility for, and disclaim any association with, the prospective financial information contained herein.

When considering the estimated cash available for distribution set forth below you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those

 

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supporting such estimated available cash. Accordingly, there can be no assurance that the forecast is indicative of our future performance. Inclusion of the forecast in this prospectus is not a representation by any person, including us or the underwriters, that the results in the forecast will be achieved.

We are providing the estimated cash available for distribution and related assumptions for the twelve months ending December 31, 2015 to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve-month period ending December 31, 2015 at our stated minimum quarterly distribution rate. Please read below under “—Assumptions and Considerations” for further information as to the assumptions we have made for the preparation of the estimated cash available for distribution set forth below. The narrative descriptions of our assumptions in “—Assumptions and Considerations” generally compare our estimated cash available for distribution for the twelve months ending December 31, 2015 with the unaudited pro forma cash available for distribution for the year ended December 31, 2013 presented under “— Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014.”

We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating our estimated cash available for distribution for the twelve months ending December 31, 2015 or to update those assumptions to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information. Components in the following table may not add or subtract to totals due to rounding.

Columbia Pipeline Partners LP

Estimated Cash Available for Distribution

 

     Twelve Months
Ending December 31,
2015
 
     (in millions)  

Operating revenues

   $ 1,449.9   

Operating expenses:

  

Operation and maintenance

     624.0   

Operation and maintenance—affiliated(1)

     151.9   

Depreciation and amortization

     140.1   

Gain on sale of assets(2)

     (20.9

Property and other taxes

     77.3   
  

 

 

 

Total operating expenses

     972.4   
  

 

 

 

Equity earnings in unconsolidated affiliates

     61.2   
  

 

 

 

Operating income

     538.7   
  

 

 

 

Interest expense—affiliated(3)

     (26.2

Other, net

     15.2   

Income taxes

     —     
  

 

 

 

Net income

     527.7   
  

 

 

 

Add:

  

Interest expense—affiliated

     26.2   

Income taxes

     —     

Depreciation and amortization

     140.1   

Distributions of earnings received from equity investees

     59.5   

Less:

  

Other, net

     15.2   

Equity earnings in unconsolidated affiliates

     61.2   
  

 

 

 

 

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Adjusted EBITDA(4)

     677.1   
  

 

 

 

Less:

  

Cash interest, expense(5)

     26.2   

Maintenance capital expenditures

     139.3   

Gain on sale of assets(6)

     20.9   

Non-recurring capital costs related to spin-off(7)

     19.8   

Expansion capital expenditures

     892.0   

Add:

  

Borrowing from affiliates of CEG to fund non-cash gain on sale of assets(8)

     20.9   

Borrowing from affiliates of CEG to fund spin-off operating and capital expenditures

     30.8   

Borrowings from affiliates of CEG and IPO proceeds to fund expansion capital expenditures(9)

     892.0   

Estimated cash available for distribution by Columbia OpCo

   $ 522.6   
  

 

 

 

Less:

  

Estimated cash available for distribution attributable to non-controlling interest in Columbia OpCo(10)

     446.2   

Cash interest, net(11)

     2.4   

Incremental general and administrative expenses(12)

     5.0   

Estimated cash available for distribution by Columbia Pipeline Partners LP

   $ 69.0   
  

 

 

 

Minimum annual distribution per unit (based on a minimum quarterly distribution rate of $0.1675 per unit)

   $ 0.6700   

Cash distributions

  

Distributions to public common unitholders

   $ 26.8   

Distributions to CEG:

  

Common units

     4.5   

Subordinated units

     31.4   
  

 

 

 

Total distributions to CEG

     35.9   
  

 

 

 

Total distributions to our unitholders at minimum rate

   $ 62.7   

Surplus ($)

     6.3   

 

(1) 

Includes forecasted expenses of $25.6 million related to the spin-off of HoldCo for the twelve months ended December 31, 2015.

(2)

Includes approximately $20.9 million attributable to the conveyance of mineral rights leases.

(3) 

Includes interest expense attributable to funds drawn by Columbia OpCo under the intercompany money pool agreement to fund expansion capital expenditures.

(4) 

For more information, please read “Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

(5) 

Calculated based on an assumed average long-term debt level of $651.3 million and assumed average short-term debt level of $96.9 million.

(6) 

Relates to a non-cash gain attributable to a mineral interest conveyance for which cash was received in a prior period.

(7) 

Represents the non-recurring capital expenditures for the twelve months ended December 31, 2015, which relate to the spin-off of HoldCo.

(8) 

Consists of borrowings by Columbia OpCo under the intercompany money pool agreement relating to non-cash gain described above.

(9) 

Consists of $689.0 million in borrowings by Columbia OpCo under the intercompany money pool agreement and net proceeds of $255.0 million from this offering that will be used to fund expansion projects. For more information, please read “Use of Proceeds.”

(10) 

Represents CEG’s 85.4% limited partner interest in Columbia OpCo.

(11) 

Cash interest includes commitment fees on, and the amortization of origination fees incurred in connection with, our new revolving credit facility.

(12) 

Reflects an adjustment for approximately $5.0 million of expenses that we expect to incur as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

 

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Assumptions and Considerations

We believe that our estimated cash available for distribution for the twelve months ending December 31, 2015 will not be less than $69.0 million. This amount of estimated cash available for distribution is approximately $13.4 million more than the pro forma cash available for distribution we generated for the twelve months ended September 30, 2014 and approximately $18.2 million more than the pro forma cash available for distribution we generated for the year ended December 31, 2013. We believe that increased income primarily from increases in revenues will result in our generating higher cash available for distribution for the twelve months ending December 31, 2015. The assumptions and estimates we have made to support our ability to generate the minimum estimated cash available for distribution are set forth below.

We have assumed we will not acquire any additional equity interests in Columbia OpCo during the twelve months ending December 31, 2015.

Regulatory, Industry and Economic Factors

Our estimate for the twelve months ending December 31, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

We assume there will not be any new federal, state or local regulations of portions of the energy industry in which we operate, or any new interpretations of existing regulations, that will be materially adverse to our business.

 

   

We assume there will not be any major adverse changes in the portions of the energy industry in which we operate or in general economic conditions.

 

   

We assume that industry, insurance and overall economic conditions will not change substantially.

 

   

We assume the organic growth projects described will not be delayed due to unusual weather or other events beyond our control.

Operating Revenues

We estimate that Columbia OpCo will generate approximately $1,449.9 million in total operating revenue for the twelve months ending December 31, 2015, compared with pro forma total operating revenue of $1,326.7 million and $1,176.7 million for the twelve months ended September 30, 2014 and the year ended December 31, 2013, respectively. Our forecast is based primarily on the following assumptions:

Transmission and Storage. Excluding tracker-related revenues, we estimate that approximately 93%, or approximately $1,064 million, of our revenue will be generated from transmission and storage services for the twelve-month period ending December 31, 2015. This compares to approximately 96%, or approximately $904 million, of our pro forma revenues that were generated from transmission and storage revenues during the year ended December 31, 2013, and approximately 93%, or approximately $937 million, of our pro forma revenues that were generated from transmission and storage revenues during the twelve-month period ended September 30, 2014. Excluding tracker-related revenues, transmission and storage revenues are expected to increase by approximately $127 million during the twelve-month period ending December 31, 2015 as compared to the pro forma twelve-month period ended September 30, 2014, primarily consisting of the following:

 

   

approximately $42.5 million of the increase is due to the net impact of the Columbia Gas Transmission modernization settlement consisting of a new demand charge known as the Capital Cost Recovery Mechanism (“CCRM”) effective February 2014 partially offset by a base rate reduction;

 

   

approximately $19.8 million of the increase is due to additional contracted firm transmission capacity from the West Side Expansion, which was placed in service in the fourth quarter of 2014;

 

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approximately $15.3 million of the increase is due to additional contracted firm transmission capacity created by the East Side Expansion, which was placed in service in the fourth quarter of 2014;

 

   

approximately $12.7 million of the increase is due to increased throughput on the Big Pine system due to planned increased production by shippers;

 

   

approximately $7.6 million of the increase is due to additional contracted firm transmission capacity from the Giles County Project, which was placed in service during the fourth quarter of 2014;

 

   

approximately $7.3 million of the increase is due to additional contracted firm transmission capacity and a full period of revenue from the Warren County Project, which went in service in the second quarter of 2014;

 

   

approximately $6.3 million of the increase is due to additional contracted firm transmission capacity from Line 1570, which was placed in service during the fourth quarter of 2014;

 

   

approximately $3.9 million of the increase is due to additional contracted firm interim transmission capacity created by the Rayne XPress project, which commenced in the fourth quarter of 2014;

 

   

approximately $2.2 million of the increase is due to additional contracted firm transmission capacity created by Big Pine Expansion, which is expected to be in service in the third quarter of 2015; and

 

   

approximately $4.4 million of the increase is due to additional contracted firm transmission capacity created by Washington County Gathering, which is expected to be in service in the fourth quarter of 2015;

 

   

partially offset by an approximate $2.2 million decrease attributable to Columbia Gulf contracts that are anticipated to not be renewed or renewed at a discount.

Trackers. We estimate that approximately 21%, or approximately $306 million, of our total operating revenue for the twelve months ending December 31, 2015 will be generated from our recovery of operating costs under certain regulatory tracker mechanisms. This compares to approximately 20%, or approximately $234 million, of our pro forma revenues that were generated from cost recovery under certain regulatory tracker mechanisms during the year ended December 31, 2013, and approximately 24%, or approximately $322 million, of our pro forma revenues that were generated from cost recovery under certain regulatory tracker mechanisms during the twelve-month period ended September 30, 2014. We expect these regulatory tracker cost recovery revenues to decrease by approximately $15.5 million during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, due to changes in timing and lower gas prices. Revenues attributable to cost recovery under certain regulatory tracker mechanisms are offset in expenses and have no impact on net income.

Other Revenue. Other revenue primarily consists of revenue from mineral rights and processing, rent and sales of gas. Excluding trackers, we estimate that approximately 7%, or approximately $78 million, of our revenue for the twelve months ending December 31, 2015 will be generated from other revenue sources. This compares to approximately 4%, or approximately $39 million, of our pro forma revenues that were generated from other revenue sources during the year ended December 31, 2013, and approximately 7%, or approximately $68 million, of our pro forma revenues that were generated from other revenue sources during the twelve-month period ended September 30, 2014. We expect our other revenues to increase by approximately $11 million during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, due to increases in royalties from mineral rights as a result of additional drilling on leased properties.

Operation and Maintenance Expense

We estimate operation and maintenance expenses will be approximately $775.9 million for the twelve months ending December 31, 2015 as compared to $741.5 million for the twelve months ended September 30,

 

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2014 and $623.9 million for the year ended December 31, 2013, respectively. Excluding tracker-related expenses, the approximate $49.9 million increase in operation and maintenance expense during the twelve-month period ending December 31, 2015, as compared to the pro forma twelve-month period ended September 30, 2014, is primarily due to:

 

   

approximately $25.6 million related to the spin-off of HoldCo, consisting of recurring costs of approximately $14.6 million related to increased shared services costs required to operate as a separate public company and approximately $11.0 million of non-recurring costs related to implementation of new accounting and software systems;

 

   

approximately $10.0 million in increased maintenance, primarily due to the timing of the integrity management program and compressor station work; and

 

   

approximately $9.9 million in increased direct labor costs.

Depreciation and Amortization Expense

We estimate total depreciation and amortization expense for the twelve months ending December 31, 2015 will be approximately $140.1 million, as compared to depreciation and amortization expense of $115.0 million for the twelve months ended September 30, 2014 and $106.1 million for the year ended December 31, 2013, both on a pro forma basis. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies, taking into account estimated capital expenditures and new assets placed into service.

Property and Other Tax Expense

We estimate our property and other taxes for the twelve months ending December 31, 2015 will be approximately $77.3 million, as compared to property and other taxes of $65.6 million for the twelve months ended September 30, 2014 and $61.9 million for the year ended December 31, 2013, both on a pro forma basis. The increase in property and other taxes is primarily due to increased property taxes resulting from new capital expansion projects.

Equity Earnings

We estimate our equity earnings for the twelve months ending December 31, 2015 will be approximately $61.2 million, as compared to equity earnings of $43.1 million for the twelve months ended September 30, 2014 and $35.8 million for the year ended December 31, 2013, both on a pro forma basis. We expect our equity earnings to increase due primarily to increases in equity earnings from Millennium Pipeline due to the Hancock Compressor Project, which went in service in the first quarter of 2014. We estimate cash distributions from our equity investments for the twelve months ending December 31, 2015 will be approximately $59.5 million as compared to cash distributions of $40.7 million for the twelve months ended September 30, 2014 and $32.1 million for the twelve months ended December 31, 2013.

Financing

We estimate that interest expense will be approximately $26.2 million for the twelve months ending December 31, 2015, as compared to $1.8 million for the year ended December 31, 2013 and $6.1 million during the twelve months ended September 30, 2014, both on a pro forma basis. Our forecasted interest expense for the twelve months ending December 31, 2015 is based on the following assumptions:

 

   

During the twelve months ending December 31, 2015, Columbia OpCo will use $255.0 million in net offering proceeds it receives from us to fund a portion of its expansion capital expenditures. All additional funding needs to fund expansion capital expenditures and spin-off operating and capital expenditures are expected to be made available from the credit facilities available to us or to Columbia OpCo. Any shortfall in our capital expenditures and expansion capital expenditures will be funded by our revolving credit facility or external equity or debt financing transactions.

 

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Columbia OpCo will have interest expense of approximately $26.2 million based on an assumed average long-term debt level of $651.3 million comprised of long-term debt remaining on Columbia OpCo’s books after formation and an assumed average short-term debt level of $96.9 million (or $689 million over the entire period) comprised of funds drawn on its $750 million of reserved borrowing capacity under the intercompany money pool agreement used to fund expansion capital expenditures and spin-off operating and capital expenditures.

 

   

We expect to have average borrowings under our new revolving credit facility of approximately $28.0 million during the twelve-month period ending December 31, 2015, which would be used to fund working capital by Columbia OpCo. We expect to pay approximately $1.5 million in credit facility commitment fees and approximately $40,000 in administrative agent fees at the closing of this offering. We have assumed that the new revolving credit facility will bear interest at an average rate of 2.35% per annum. An increase or decrease of 1.0% in the interest rate will result in increased or decreased annual interest expense of $0.3 million.

 

   

Interest expense also includes the amortization of origination fees of $1.8 million which are assumed to be incurred in connection with our new revolving credit facility. These fees are expected to be amortized at a rate of approximately $0.3 million per year.

 

   

Our borrowing capacity for Columbia OpCo and its subsidiaries under the intercompany money pool arrangement is limited to $750 million, plus any additional available capacity on NiSource’s revolving credit facility, up to a combined maximum level of $1 billion dollars. In addition, we will also have access to a $500 million revolving credit facility at the Partnership. In the event that the separation of HoldCo from NiSource occurs, Columbia OpCo will have access to an intercompany money pool arrangement with HoldCo with $750 million of reserved borrowing capacity, with additional capacity as available under the HoldCo revolving credit facility, up to a combined maximum level of $1.5 billion. To the extent our capital requirements exceed amounts available under our combined credit facilities, we will be required to fund such amounts by seeking to increase our borrowing capacity under these facilities or seek to issue debt or equity in private placements or public offerings, subject to market conditions.

Capital Expenditures

We maintain an ongoing program of continually investing in our business. Our expenditures include ongoing expenditures required to maintain operating capacity, system integrity and reliability as well as expansion projects that increase capacity or allow us to operate more efficiently. We categorize our capital expenditures as either:

 

   

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the construction, development or acquisition of additional pipeline, storage or gathering capacity, as well as the Columbia Gas Transmission modernization program, to the extent such capital expenditures are expected to expand our operating capacity or our operating income. In particular, the Columbia Gas Transmission modernization program, which includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems, is expected to primarily increase our long-term operating income by allowing us to recover certain invested capital under the CCRM. For more information, please refer to Note 8 “Regulatory Matters” in the audited Notes to Combined Financial Statements.

 

   

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new assets to replace or improve existing assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

 

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We estimate that total capital expenditures for Columbia OpCo for the twelve months ending December 31, 2015 will be $1,051.1 million, compared to $856.9 million for the twelve months ended September 30, 2014 and $790.6 million for the year ended December 31, 2013 on a pro forma basis. Our estimate is based on the following assumptions:

Expansion Capital Expenditures. We estimate expansion capital expenditures to be $892.0 million for the twelve months ending December 31, 2015, as compared to $715.8 million for the twelve months ended September 30, 2014 and $658.9 million for the year ended December 31, 2013. We intend to finance these expansion capital expenditures as described above. These expenditures are primarily comprised of the following expansion capital projects that we intend to pursue during the forecast period:

 

   

approximately $300 million in connection with the modernization program, which involves replacement and improvement of aging infrastructure, upgrading compression and expanding in-line inspection capability;

 

   

approximately $179 million for East Side Expansion, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets;

 

   

approximately $148 million for Rayne XPress and Leach XPress, which involves adding 124 miles of 36-inch pipeline from Majorsville to Crawford CS, 27 miles of 36-inch pipeline from Crawford CS to McArthur CS and approximately 163,700 horsepower of compression across multiple sites;

 

   

approximately $61 million for the Big Pine Expansion, which involves the addition of 9 miles of 20-inch pipeline and compression facilities that will add incremental capacity to the Big Pine pipeline;

 

   

approximately $58 million for Washington County Gathering System, which involves construction of a 21-mile dry gas field gathering system with compression, measurement and dehydration facilities to feed into Line 1570;

 

   

approximately $42 million for West Side Expansion, which involves increasing supply takeaway from the Marcellus to Gulf Coast and Southeast markets with piping modifications and compression to add 980,000 Dth/d of capacity;

 

   

approximately $32 million for WB XPress, which involves approximately 29 miles of various sized pipe, 170,000 horsepower of compression, various system and station modification along line WB to add 1,300,000 Dth/d of capacity to expanding eastern and Gulf coast markets;

 

   

approximately $22 million for CEVCO investments, which involves an investment in the Cardinal Upstream project, in which we are a 5% working interest owner with Hilcorp in the development of wells in a specified acreage area in the Utica/Point Pleasant formation;

 

   

approximately $20 million for the Kentucky Power Plant Project, which involves the addition of 2.7 miles of 16-inch greenfield pipeline from Columbia Gas Transmission’s Line P to a third-party power plant, point of delivery meter site in the existing third-party plant, regulation at the Kenova compressor station, and regulation and a heater at the intersection of Line P and SM-102;

 

   

approximately $13 million for Cameron Access Project, which involves the addition of a 26-mile pipeline and compressor; improvements to existing pipeline and compression facilities, and a new compressor station; 800,000 Dth/d of additional capacity from Rayne, LA compressor station to the Cameron LNG terminal; and

 

   

approximately $13 million for Utica Access, which involves the addition of 4.7 miles of 20-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on its system.

Our ability to finance our expansion capital expenditures will depend in part on our ability to fund them from borrowings rather than from cash generated from our operations or from proceeds from the sale of equity interests in Columbia OpCo. While our debt facilities will not be fully drawn during the 12 months ending December 31, 2015, there is no guarantee that expansion capital expenditures incurred after December 31, 2015

 

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could be funded from borrowings. If we are unable to borrow to finance our expansion capital expenditures in the future, we would need to fund them from either proceeds from the sale of equity interests in Columbia OpCo to the Partnership or to third parties or from operating cash flows, which would significantly reduce the amount of cash available for distribution to our unitholders.

Maintenance Capital Expenditures. We estimate total maintenance capital expenditures to be $139.3 million for the twelve months ending December 31, 2015. This compares to $141.1 million for the twelve months ended September 30, 2014 and $131.7 million for the year ended December 31, 2013 on a pro forma basis. We estimate this decrease will be due to the timing of maintenance projects. We expect to fund these maintenance capital expenditures with cash generated by our operations. We expect ongoing maintenance capital expenditures to be approximately $135 million per year in the near term.

Non-Recurring Capital Expenditures Related to Spin-Off. We estimate $19.8 million of non-recurring capital expenditures related to the spin-off of HoldCo for the twelve months ending December 31, 2015.

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2015, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.1675 per unit, or $0.67 on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the distribution for the period after the closing of this offering through March 31, 2015.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders. Any distribution of capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please see “—Distributions From Capital Surplus.” In determining operating surplus and capital surplus, we will only take into account our proportionate share of our consolidated subsidiaries that are not wholly owned, such as Columbia OpCo.

Operating Surplus

We define operating surplus as:

 

   

$62 million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination of any hedge contract prior to its

 

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stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

 

   

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus

 

   

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our general partner or the boards of any of our subsidiaries to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

 

   

any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to described in the first bullet above). Operating surplus is not limited to cash generated by our operations. For example, it includes a basket of $62 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction. Our general partner may treat the temporary use of cash reserved to fund expansion capital expenditures as a working capital borrowing, and may use such cash to temporarily fund operating expenditures. When such expansion capital expenditures are in fact made (or twelve months after the date such cash was used, if earlier), the amount temporarily used as working capital borrowings shall be treated as a repayment of working capital borrowings.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly

 

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installments over the remaining scheduled life of such hedge contract), officer and director compensation, repayment of working capital borrowings, interest on indebtedness and maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

 

   

repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

 

   

payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

 

   

expansion capital expenditures;

 

   

investment capital expenditures;

 

   

payment of transaction expenses relating to interim capital transactions;

 

   

distributions to our partners (including distributions in respect of our incentive distribution rights); or

 

   

repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity interests; and

 

   

sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long term. Examples of expansion capital expenditures

 

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include the development of a new facility or the expansion of an existing facility, to the extent such expenditures are expected to expand our long-term operating capacity or net income. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of such construction, development or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures, including transaction expenses, which are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of cash expenditures made for investment purposes. Examples of investment capital expenditures include traditional cash expenditures for investment purposes, such as purchases of securities, as well as other cash expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or net income, but which are not expected to expand, for more than the short term, our operating capacity or net income.

As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition, construction, development or expansion and ends on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.1675 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

 

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Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending March 31, 2018, if each of the following has occurred:

 

   

for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding for each quarter of each period;

 

   

for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

For the period after closing of this offering through March 31, 2015, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending March 31, 2016, if each of the following has occurred:

 

   

for the four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded the product of 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;

 

   

for the same four-quarter period, the “adjusted operating surplus” equaled or exceeded the product of 150.0% of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

 

   

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions.

 

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Adjusted Operating Surplus

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

 

   

operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

   

any net increase during that period in working capital borrowings; less

 

   

any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; less

 

   

any expenditures that are not operating expenditures solely because of the provision described in the last bullet point describing operating expenditures above; plus

 

   

any net decrease during that period in working capital borrowings; plus

 

   

any net increase during that period in cash reserves for operating expenditures required by any debt instrument for the repayment of principal, interest or premium; plus

 

   

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

Distributions From Operating Surplus During the Subordination Period

If we make a distribution from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

 

   

first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

 

   

second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions From Operating Surplus After the Subordination Period

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

 

   

first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—Incentive Distribution Rights” below.

 

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General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. CEG currently holds the incentive distribution rights, but may transfer these rights separately.

If for any quarter:

 

   

we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

   

we have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

 

   

first, to all common unitholders and subordinated unitholders, pro rata, until each unitholder receives a total of $0.192625 per unit for that quarter (the “first target distribution”);

 

   

second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.209375 per unit for that quarter (the “second target distribution”);

 

   

third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.251250 per unit for that quarter (the “third target distribution”); and

 

   

thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

 

    

Total Quarterly

Distribution Per Unit

   Marginal Percentage Interest in
Distributions
 
        Unitholders     IDR Holders  

Minimum Quarterly Distribution

   up to $0.16750      100.0     0

First Target Distribution

   above $0.16750 up to $0.192625      100.0     0

Second Target Distribution

   above $0.192625 up to $0.209375      85.0     15.0

Third Target Distribution

   above $0.209375 up to $0.251250      75.0     25.0

Thereafter

   above $0.251250      50.0     50.0

 

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IDR Holders’ Right to Reset Incentive Distribution Levels

CEG, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If CEG transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that CEG holds all of the incentive distribution rights at the time that a reset election is made.

The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for the prior four consecutive fiscal quarters and such distributions did not exceed the adjusted operating surplus for such period. The reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset election and higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. Because the reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset, if we were to issue additional common units after the reset and maintain the per unit distribution level, no additional incentive distributions would be payable. By contrast, if there were no such reset and we were to issue additional common units and maintain the per unit distribution level, additional incentive distributions would have to be paid based on the additional number of outstanding common units and the percentage interest of the incentive distribution rights above the target distribution levels. Thus, the exercise of the reset right would lower our cost of equity capital. CEG could exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by CEG of incentive distribution payments based on the target cash distributions prior to the reset, CEG will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

 

   

first, to all common unitholders, pro rata, until each unitholder receives an amount per unit for that quarter equal to 115.0% of the reset minimum quarterly distribution;

 

   

second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 125.0% of the reset minimum quarterly distribution;

 

   

third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 150.0% of the reset minimum quarterly distribution; and

 

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thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $0.30.

 

   

Quarterly Distribution

Per Unit Prior to Reset

  Unitholders     IDR Holders    

Quarterly Distribution Per
Unit Following Hypothetical

Reset

Minimum Quarterly Distribution

  up to $0.16750     100.0     0.0   up to $0.3000(1)

First Target Distribution

  above $0.16750 up to $0.192625     100.0     0.0   above $0.3000 up to $0.3450(2)

Second Target Distribution

  above $0.192625 up to $0.209375     85.0     15.0   above $0.3450 up to $0.3750(3)

Third Target Distribution

  above $0.209375 up to $0.251250     75.0     25.0   above $0.3750 up to $0.4500(4)

Thereafter

  above $0.251250     50.0     50.0   above $0.4500

 

(1) This amount is equal to the hypothetical reset minimum quarterly distribution.
(2) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
(4) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be 93,622,796 common units outstanding and the distribution to each common unit would be $0.30 for the quarter prior to the reset.

 

   

Quarterly Distribution

Per Unit 

  Common Unitholders
Cash
Distribution
    Cash Distributions
to Holders of
IDRs Prior to

Reset
    Total
Distributions
 

Minimum Quarterly Distribution

  up to $0.16750   $ 15,681,818      $ —        $ 15,681,818   

First Target Distribution

  above $0.16750 up to $0.192625     2,352,273        —          2,352,273   

Second Target Distribution

  above $0.192625 up to $0.209375     1,568,182        276,738        1,844,920   

Third Target Distribution

  above $0.209375 up to $0.251250     3,920,455        1,306,818        5,227,273   

Thereafter

  above $0.251250     4,564,111        4,564,111        9,128,223   
   

 

 

   

 

 

   

 

 

 
    $ 28,086,839      $ 6,147,667      $ 34,234,506   
   

 

 

   

 

 

   

 

 

 

 

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The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of our incentive distribution rights with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be 114,115,019 common units outstanding and the distribution to each common unit would be $0.30. The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $6,147,667 , by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $0.30.

 

   

Quarterly Distribution

per Unit

  Cash
Distributions
to Common
Unitholders
After Reset
    General Partner
Cash Distributions
    Total
Distributions
 
        Common
Units(1)
    IDRs     Total    

Minimum Quarterly Distribution

  up to $0.3000   $ 28,086,839      $ 6,147,667      $ 0      $ 6,147,667      $ 34,234,506   

First Target Distribution

  above $0.3000 up to $0.3450          

Second Target Distribution

  above $0.3450 up to $0.3750          

Third Target Distribution

  above $0.3750 up to $0.4500          

Thereafter

  above $0.4500          
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $ 28,086,839      $ 6,147,667      $ 0      $ 6,147,667      $ 34,234,506   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Represents distributions in respect of the common units issued upon the reset.

The holders of IDRs will be entitled to cause the target distribution levels to be reset on more than one occasion.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

 

   

first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

 

   

second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

   

thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution of capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights, pro rata.

 

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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

   

the minimum quarterly distribution;

 

   

the target distribution levels;

 

   

the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

 

   

the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

 

   

the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

 

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Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

 

   

first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

 

   

second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

   

third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

   

fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

 

   

fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights for each quarter of our existence;

 

   

sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights for each quarter of our existence; and

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to holders of our incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Whether the liquidation occurs before or after the end of the subordination period, prior to making the adjustments for gains described above, we may make special allocations of gain among the partners in a manner to create economic uniformity among the common units held by CEG, common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

   

first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

 

   

second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

 

   

thereafter, 100.0% to our general partner.

 

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If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Whether the liquidation occurs before or after the end of the subordination period, prior to making the adjustments for losses described above, we may make special allocations of loss among the partners in a manner to create economic uniformity among the common units held by CEG, common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made. In addition, we may make special allocations of unrealized gain and loss among the partners in a manner to create economic uniformity among the common units held by CEG, common units into which the subordinated units convert and the common units held by public unitholders.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows selected historical financial and operating data of Columbia Pipeline Partners LP Predecessor (the “Predecessor”) and pro forma financial data of the Partnership for the periods and as of the dates indicated.

The historical financial statements of the Predecessor reflect 100% of the Predecessor’s operations. The assets of the Partnership on the closing date of the offering will consist only of the acquired interest in Columbia OpCo. Columbia OpCo’s assets will consist of the following wholly owned subsidiaries of the Predecessor, Columbia Gas Transmission, LLC, Columbia Gulf Transmission, LLC, Columbia Midstream Group, LLC and Columbia Energy Ventures, LLC, and equity method investments in Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C., and Pennant Midstream, LLC.

The selected historical financial data presented as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 are derived from the audited financial statements of the Predecessor, which are included elsewhere in this prospectus. The selected historical financial data presented as of September 30, 2014 and for the nine months ended September 30, 2014 and 2013 are derived from the unaudited financial statements of the Predecessor, which are included elsewhere in this prospectus. The selected financial data presented as of December 31, 2011, 2010 and 2009 and September 30, 2013, and for the years ended December 31, 2010 and 2009 are derived from the unaudited financial statements of the Predecessor, which are not included elsewhere in this prospectus.

The selected pro forma financial data as of September 30, 2014 and for the fiscal year ended December 31, 2013 and nine months ended September 30, 2014 are derived from the unaudited pro forma financial statements of the Partnership. The unaudited pro forma combined statements of operations for the year ended December 31, 2013 and for the nine months ended September 30, 2014 assume this offering and related transactions occurred on January 1, 2013. The unaudited pro forma combined balance sheet as of September 30, 2014 assumes the offering and related transactions occurred on September 30, 2014. The pro forma financial data give pro forma effect to:

 

   

the assumption by CEG, the Partnership’s sponsor, of the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and the novation by NiSource Finance of that $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

the contribution by CEG of substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

the receipt by the Partnership of gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units to the public at an assumed initial offering price of $20.00 per unit in this offering, the midpoint of the price range on the cover of this prospectus;

 

   

the contribution by CEG (which will own all of Columbia OpCo’s limited partner interests) of an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

   

in exchange for CEG’s contribution, the issuance by the Partnership to CEG of 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

the use by the Partnership of $45.0 million of the proceeds from the offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

the use by the Partnership of $755.0 million of proceeds from the offering to purchase from Columbia OpCo an additional an approximate 6.2% limited partner interest in Columbia OpCo, resulting in the Partnership owning a 14.6% limited partner interest in Columbia OpCo;

 

   

the use by Columbia OpCo of $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

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the entry by the Partnership into a $500 million revolving credit facility, which is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo and under which no amounts will be drawn at the closing of this offering. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

the entry by Columbia OpCo and its subsidiaries into the money pool agreement with $750 million of reserved borrowing capacity, under which no amounts will be drawn at the closing of this offering; and

 

   

the entry by the Partnership and Columbia OpCo into an omnibus agreement and a service agreement with CEG and its affiliates.

We have not given pro forma effect to incremental general and administrative expenses of approximately $5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer insurance expenses; and director and officer compensation expenses.

For a detailed discussion of the selected historical financial information contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds,” “Business—Our Relationship with Our Sponsor” and the audited and unaudited historical financial statements of the Predecessor and our unaudited pro forma combined financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net. Adjusted EBITDA is not calculated or presented in accordance with generally accepted accounting principles (“GAAP”). We explain this measure under “—Non-GAAP Financial Measures” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners LP
Pro Forma
 
    Year Ended December 31,     Nine Months Ended
September 30,
    Nine Months
Ended
September 30,
2014
    Year Ended
December 31,
2013
 
    2013     2012     2011     2010     2009     2014     2013      
    (in millions, except per unit and operating data)  

Statement of Operations Data:

             

Total Operating Revenues

  $ 1,179.4      $ 1,000.4      $ 1,005.6      $ 949.2      $ 930.7      $ 1,006.5      $ 857.6      $ 1,005.4      $ 1,176.7   

Operating Expenses:

             

Operation and maintenance

    507.1        374.2        377.9        325.5        312.9        477.1        366.7        454.6        481.4   

Operation and maintenance—affiliated

    118.1        105.6        98.3        75.6        72.1        89.6        82.4        111.1        142.5   

Depreciation and amortization

    106.9        99.3        130.0        130.7        121.5        87.7        78.9        87.2        106.1   

(Gain) loss on sale of assets

    (18.6     (0.6     0.1        (0.1     (1.4     (20.8     (11.3     (20.8     (18.6

Property and other taxes

    62.2        59.2        56.6        57.4        55.9        50.3        46.6        50.1        61.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

  $ 775.7      $ 637.7      $ 662.9      $ 589.1      $ 561.0      $ 683.9      $ 563.3      $ 682.2      $ 773.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

    35.9        32.2        14.6        15.0        16.0        32.9        25.6        32.9        35.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

  $ 439.6      $ 394.9      $ 357.3      $ 375.1      $ 385.7      $ 355.5      $ 319.9      $ 356.1      $ 439.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

             

Interest expense—affiliated

    (37.9     (29.5     (29.8     (25.9     (25.0     (39.1     (27.6     (5.7     (1.8

Other, net

    17.6        1.5        1.2        1.6        3.6        8.0        15.3        8.0        22.6   

Income taxes

    152.4        136.9        125.6        130.4        146.9        119.7        112.4        0.2        0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

  $ 266.9      $ 230.0      $ 203.1      $ 220.4      $ 217.4      $ 204.7      $ 195.2      $ 358.2      $ 459.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

             

Net income attributable to non-controlling interests

              (305.9 )     (392.7 )
               

 

 

   

 

 

 

Net income attributable to Columbia Pipeline Partners LP

            $ 52.3      $ 67.1   
               

 

 

   

 

 

 

 

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    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners LP
Pro Forma
 
    Year Ended December 31,     Nine Months Ended
September 30,
    Nine Months
Ended
September 30,

2014
    Year Ended
December 31,

2013
 
    2013     2012     2011     2010     2009     2014     2013      
    (in millions, except per unit and operating data)  

Limited partner interests in net income:

             

Common units

                $ 26.2      $ 33.6   

Subordinated units

                $ 26.1      $ 33.5   

Net income per limited partner unit (basic and diluted):

             

Common units

                $ 0.56      $ 0.72   

Subordinated units

                $ 0.56      $ 0.72   

Balance Sheet Data (at period end):

             

Total assets

  $ 7,261.8      $ 6,623.2      $ 6,142.6      $ 5,934.9      $ 5,767.2      $ 7,806.8      $ 6,997.5      $ 8,014.5     

Net property, plant and equipment

    4,303.4        3,741.5        3,398.7        3,224.2        3,110.7        4,790.1        4,143.5        4,770.4     

Long-term debt-affiliated, excluding amounts due within one year

    819.8        754.7        294.7        453.4        453.6        1,370.9        754.7        511.6     

Total liabilities

    3,361.9        2,883.7        2,430.6        2,244.5        2,047.8        3,701.4        3,167.2        1,320.8     

Total partners’ net equity

    3,899.9        3,739.5        3,712.0        3,690.4        3,719.4        4,105.4        3,830.3        6,693.7     

Statement of Cash Flow Data:

             

Net cash from (used for):

                 

Operating activities

  $ 454.0      $ 474.9      $ 435.3      $ 376.0      $ 495.4      $ 446.6      $ 316.5       

Investing activities

    (797.4     (455.5     (307.2     (297.3     (182.5     (618.6     (527.6    

Financing activities

    343.1        (18.8     (128.1     (78.9     (313.0     172.1        210.6       

Other Data:

             

Adjusted EBITDA

  $ 542.7      $ 496.9      $ 491.5      $ 503.7      $ 491.2      $ 437.9      $ 392.2      $ 438.0      $ 541.6   

Adjusted EBITDA attributable to non-controlling interest

                $ (374.1   $ (462.5

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

                $ 63.9      $ 79.1   

Maintenance capital expenditures

    132.7        209.6        220.0        149.6        116.2        90.1        80.3       

Expansion capital expenditures

    664.8        280.0        81.5        152.4        171.2        536.3        476.2       

Operating Data:(1)

             

Contracted firm capacity (MMDth/d)

    12.9        13.2        13.2        11.9        12.0        12.8        12.7       

Throughput (MMDth)

    1,997.3        2,200.0        2,393.7        2,154.4        2,145.3        1,497.2        1,492.1       

Natural gas storage capacity (MMDth)

    287        283        282        283        283        287        287       

 

(1) 

Excludes equity investments.

Non-GAAP Financial Measures

Adjusted EBITDA

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash flows from operating activities. You should not

 

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consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following tables present a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

    Columbia Pipeline Partners LP
Predecessor Historical
    Columbia Pipeline Partners LP
Pro Forma
 
    Year Ended December 31,     Nine Months
Ended
September 30,
    Nine Months
Ended
September 30,

2014
    Year Ended
December 31,

2013
 
    2013     2012     2011     2010     2009     2014     2013      
    (in millions)  

Net Income

  $ 266.9      $ 230.0      $ 203.1      $ 220.4      $ 217.4      $ 204.7      $ 195.2      $ 358.2      $ 459.8   

Add:

                 

Interest expense—affiliated

    37.9        29.5        29.8        25.9        25.0        39.1        27.6        5.7        1.8   

Income taxes

    152.4        136.9        125.6        130.4        146.9        119.7        112.4        0.2        0.2   

Depreciation and amortization

    106.9        99.3        130.0        130.7        121.5        87.7        78.9        87.2        106.1   

Distributions of earnings received from equity investees

    32.1        34.9        18.8        12.9        —          27.6        19.0        27.6        32.1   

Less:

                 

Other, net

    17.6        1.5        1.2        1.6        3.6        8.0        15.3        8.0        22.6   

Equity earnings in unconsolidated affiliates

    35.9        32.2        14.6        15.0        16.0        32.9        25.6        32.9        35.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 542.7      $ 496.9      $ 491.5      $ 503.7      $ 491.2      $ 437.9      $ 392.2      $ 438.0      $ 541.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

                 

Adjusted EBITDA attributable to non-controlling interest

                  (374.1     (462.5

Adjusted EBITDA attributable to Columbia Pipeline Partners LP

                $ 63.9      $ 79.1   
               

 

 

   

 

 

 

 

    Columbia Pipeline Partners LP
Predecessor Historical
 
    Year Ended December 31,     Nine Months Ended
September 30,
 
    2013     2012     2011     2010     2009     2014     2013  
    (in millions)  

Net Cash Flows from Operating Activities

  $ 454.0      $ 474.9      $ 435.3      $ 376.0      $ 495.4      $ 446.6      $ 316.5   

Interest expense—affiliated

    37.9        29.5        29.8        25.9        25.0        39.1        27.6   

Current taxes

    (27.5     92.2        48.8        40.1        (8.0     50.2        (39.3

Other adjustments to operating cash flows

    6.1        1.4        (4.1     9.8        (2.1     14.3        (2.4

Changes in assets and liabilities

    72.2        (101.1     (18.3     51.9        (19.1     (112.3     89.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 542.7      $ 496.9      $ 491.5      $ 503.7      $ 491.2      $ 437.9      $ 392.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of financial condition and results of operations should be read in conjunction with our historical financial statements and notes and our pro forma financial statements and notes included elsewhere in this prospectus.

This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included elsewhere in this prospectus.

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. Our business and operations will be conducted through Columbia OpCo, a recently formed partnership between CEG and us. At the completion of this offering, our assets will consist of a 14.6% limited partner interest in Columbia OpCo, as well as the non-economic general partner interest in Columbia OpCo. Through our ownership of Columbia OpCo’s general partner, we will control all of Columbia OpCo’s assets and operations.

Columbia OpCo owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2013, 93% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years.

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited partnership interests in Columbia OpCo in connection with its issuance of any new equity interests.

Interstate Pipeline and Storage Assets. Through our ownership interests in Columbia OpCo, we own the following natural gas transportation and storage assets, which are regulated by the FERC:

 

   

Columbia Gas Transmission, LLC (“Columbia Gas Transmission”). Columbia OpCo owns 100% of the ownership interests in Columbia Gas Transmission, which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shales and other producing basins to the midwest, mid-Atlantic and northeast regions. The system consists of approximately 11,200 miles of natural gas transmission pipeline, 89 compressor stations with 617,185 horsepower of installed capacity and approximately 3,400 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

 

   

Columbia Gulf Transmission, LLC (“Columbia Gulf”). Columbia OpCo owns 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with approximately 3,400 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus shale and Utica, Columbia Gulf has recently executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. As a result, once these projects are completed, the system will be able to receive Marcellus and Utica supplies, through upstream pipelines such as

 

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Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including LNG export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

 

   

Millennium Pipeline Joint Venture (“Millennium Pipeline”). Columbia OpCo owns a 47.5% ownership interest in Millennium Pipeline Company, L.L.C., which transports an average of 1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator for the pipeline and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

 

   

Hardy Storage Joint Venture (“Hardy Storage”). Columbia OpCo owns a 49% ownership interest in Hardy Storage Company, LLC, which owns an underground natural gas storage field in the Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth. Columbia Hardy Corporation, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% ownership interest, respectively, in Hardy Storage.

Gathering, Processing and Other Assets. Through our ownership interests in Columbia OpCo, we own the following gathering, processing and other assets:

Columbia Midstream Group, LLC (“Columbia Midstream”). Columbia OpCo owns 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 104 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale plays.

Pennant Midstream, LLC (“Pennant”). Columbia OpCo owns a 50% ownership interest in Pennant, which owns approximately 43 miles of wet natural gas gathering pipeline infrastructure, a gas processing facility and a natural gas liquids (“NGL”) pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp Energy Company (“Hilcorp”) jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

Columbia Energy Ventures, LLC (“CEVCO”) and Other. Columbia OpCo owns 100% of the ownership interests in CEVCO, which manages Columbia OpCo’s mineral rights positions in the Marcellus and Utica shale areas. CEVCO owns production rights to over 450,000 acres and has sub-leased the production rights in four storage fields and has also contributed its productions rights in one other field. In addition, Columbia OpCo owns 100% of the ownership interests in CNS Microwave, Inc. (“CNS Microwave”), which provides ancillary communication services to us and third parties.

Spin-off

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo, which is expected to have an investment grade rating. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur or that HoldCo will receive an investment grade rating. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner, 85.4% of the limited partner interests in Columbia OpCo and the limited partnership interests in us that are not owned by the public. Even if

 

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the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG, our sponsor. Successful completion of the spin-off could impact our business and operations in a number of positive ways, including increased focus of management and resources on our business and operations. However, the spin-off could adversely impact our business by reducing potential access to financial support from HoldCo and CEG or as a result of recruitment and retention employee issues, increased costs associated with HoldCo becoming a standalone public entity and potential limits on our business operations as a result of certain covenants we agree to make in our omnibus agreement in connection with the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Please read “Business—Spin-Off.”

Factors and Trends That Impact Our Business

Key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate; our customers and their requirements; and the government regulation of natural gas production, pipelines and storage. These key factors also play an important role in how we evaluate our business and how we implement our long-term strategies.

Natural Gas Supply and Demand Dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. The NYMEX natural gas futures contract reached a high of $13.58/MMBtu in July 2008, but has declined significantly from that high as a result of increased natural gas supply, due in large part to increased production of unconventional sources such as natural gas shale plays particularly in the Marcellus and Utica shale regions. To illustrate, the U.S. Energy Information Administration (“EIA”) reported dry gas production for the month of December 2008, at 1,744,458 million cubic feet. That same statistic increased to 2,105,959 million cubic feet in June 2014. Additionally, due to the longer lead times associated with pipeline infrastructure build-outs, pipeline capacity to transport natural gas out of these shale producing regions is constrained and has led to strong interest in pipeline expansions out of the region. The significant increase in supply has maintained downward pressure on the price of natural gas with the prompt month NYMEX natural gas futures price at $3.19/MMBtu as of December 29, 2014. We believe that over the short term, natural gas prices are likely to remain relatively flat until the supply overhang has been reduced by infrastructure build-outs to connect production with consuming regions and/or exportation.

Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional sources (defined by the EIA as natural gas produced from shale formations, tight gas and coal beds). While the EIA expects total domestic natural gas production to grow from approximately 24.2 Tcf in 2013 to 36.1 Tcf in 2035, it expects shale gas production to grow to 18.5 Tcf in 2035, or 51% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these shale plays at cost-advantaged per unit economics as compared to most conventional shale plays.

As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment. We believe our assets are well positioned to take advantage of the current drilling focus in liquids-rich regions.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, exportation off the continent via LNG, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. This displacement will continue due to lower cost of natural gas as a fuel for electric generation and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in 2010, approximately 45% of the electricity in the U.S. was generated by coal-fired power plants, and in 2013,

 

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approximately 39% of the electricity in the U.S. was generated by coal-fired power plants. In addition, the EIA’s 2014 Annual Energy Outlook projects that annual domestic consumption of natural gas will increase by approximately 16.5% from 24.9 quadrillion Btu in 2011 to 29.0 quadrillion Btu in 2025.

Growth Associated with Expansions. As production and demand for our services increase in our areas of operations, we believe that we are well-positioned to attract volumes to our systems through cost-effective capacity expansions. For example, we have recently completed or we are currently undertaking the following expansions:

 

   

Warren County Project. We recently completed construction of approximately 2.5 miles of new 24-inch pipeline and modifications to existing compressor stations for a total capital cost of approximately $37 million. This project has expanded the system in order to provide up to nearly 250,000 Dth/d of transportation capacity under a long-term, firm contract. The project commenced commercial operations in April 2014.

 

   

West Side Expansion (Columbia Gas Transmission—Smithfield III). This project is designed to provide a market outlet for increasing Marcellus supply originating from the Waynesburg, West Virginia and Smithfield, Pennsylvania areas on the Columbia Gas Transmission system. We invested approximately $87 million in new pipeline and compression, which will provide up to 444,000 Dth/d of incremental, firm transport capacity and is supported by long-term, firm contracts. The project was placed in service during the fourth quarter of 2014.

 

   

West Side Expansion (Columbia Gulf—Bi-Directional). Under this project we are investing approximately $113 million in system modifications and horsepower to provide a firm backhaul transportation path from the Leach, Kentucky interconnect with Columbia Gas Transmission to Gulf Coast markets on the Columbia Gulf system. This investment will increase capacity up to 540,000 Dth/d to transport Marcellus production originating in West Virginia. The project is supported by long-term firm contracts and was placed in service in the fourth quarter of 2014. The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

 

   

Giles County Project. We invested approximately $25 million for the construction of approximately 12.9 miles of 8-inch pipeline, which will provide 46,000 Dth/d of firm service to a third party located off its Line KA system and into Columbia of Virginia’s system. We have secured a long-term firm contract for the full delivery volume and the project was placed in service in the fourth quarter of 2014.

 

   

Line 1570 Expansion. We are replacing approximately 19 miles of existing 20-inch pipeline with a 24-inch pipeline and adding compression at an approximate cost of $18 million. The project, which was placed in service during the fourth quarter of 2014, creates nearly 99,000 Dth/d of capacity and is supported by long-term, firm contracts.

 

   

Chesapeake LNG. The project involves the investment of approximately $33 million to replace 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives. This project is expected to be placed in service in the second quarter of 2015.

 

   

Big Pine Expansion. We are investing approximately $65 million to make a connection to the Big Pine pipeline and add compression facilities that will add incremental capacity. The additional 9-mile 20-inch pipeline and compression facilities will support Marcellus shale production in western Pennsylvania. We expect 50% of the increased capacity generated by the project to be supported by a long-term fee-based agreement with a regional producer, with the remaining capacity expected to be sold to other area producers in the near term. We expect the project to be placed in service by the third quarter of 2015.

 

   

East Side Expansion. We have requested FERC authorization to construct facilities for this project, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets. Supported by long-term firm contracts, the project will add up to 312,000 Dth/d of capacity and is expected to be placed in service by the end of the third quarter of 2015. We plan to invest up to approximately $275 million in this project.

 

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Kentucky Power Plant Project. We expect to invest approximately $24 million to construct 2.7 miles of 16-inch greenfield pipeline and other facilities to a third-party power plant from Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service, is supported by a long-term firm contract, and is expected to be placed in service by the end of the second quarter of 2016.

 

   

Utica Access Project. We intend to invest approximately $51 million to construct 4.7 miles of 20-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on our system. This project is expected to be in service by the end of the fourth quarter of 2016. We have secured firm contracts for the full delivery volume.

 

   

Leach XPress. We finalized agreements for the installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system, and 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system, and approximately 101,700 horsepower across multiple sites to provide approximately 1,500,000 Dth/d of capacity out of the Marcellus and Utica production regions to the Leach compressor station (“Leach CS”) located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. Virtually all of the project’s capacity has been secured with long-term firm contracts. We expect the project to go in service during the fourth quarter of 2017 and will invest approximately $1.42 billion in the Leach XPress project.

 

   

Rayne XPress. This project would transport approximately 1 MMDth/d of growing southwest Marcellus and Utica production away from constrained production areas to markets and liquid transaction points. Capable of receiving gas from Columbia Gas Transmission’s Leach XPress project, gas would be transported from the Leach, Kentucky interconnect with Columbia Gas Transmission in a southerly direction towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. We have secured definitive agreements for firm service for the project’s capacity and expect the project to be placed in service by the end of the fourth quarter of 2017. We expect to invest approximately $330 million on the Rayne XPress project to modify existing facilities and to add new compression.

 

   

Cameron Access Project. We are investing approximately $310 million in an 800,000 Dth/d expansion of the Columbia Gulf system through improvements to existing pipeline and compression facilities, a new state-of-the-art compressor station near Lake Arthur, Louisiana, and the installation of a new 26-mile pipeline in Cameron Parish to provide for a direct connection to the Cameron LNG Terminal. We expect the project to be placed in service by the first quarter of 2018 and have secured long-term firm contracts for approximately 90% of the increased volumes.

 

   

WB XPress. We expect to invest approximately $870 million in this project to expand the WB system through looping and add compression in order to transport approximately 1.3 MMDth of Marcellus Shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which include access to the Cove Point LNG terminal. We expect this project to be placed in service by the fourth quarter of 2018.

Finally, we and our customers have agreed to a mechanism that provides recovery and return on our initial investment of up to $1.5 billion over a five-year period, beginning in 2013, to modernize our system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement with the FERC, we must annually incur at least $100 million in maintenance capital expenditures in order to trigger the terms of the modernization settlement’s recovery mechanism. During 2013, we completed more than 30 individual projects representing a total investment of approximately $300 million. The modernization program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

 

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Our Customers. Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. Our customers use our transportation services for a variety of reasons:

 

   

LDCs, municipal utilities, and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. These customers will typically enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract;

 

   

Producers of natural gas and LNG exporters require the ability to deliver their product to market and typically enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity; and

 

   

Marketers use our transportation services to capitalize on natural gas price volatility over time or between markets.

Impact of New Supply Basins and End-Use Markets. The Columbia Gulf pipeline system was originally constructed for the primary purpose of moving natural gas produced on the Gulf Coast north through Columbia Gas Transmission to midwestern and mid-Atlantic end-use markets. Increases in production in the Marcellus and Utica regions have resulted in a shift of production supply to Northeast markets, displacing the need for production in the Gulf Coast and other Western supply sources. In the past several years, access to new supply and access to new markets have been added to the system through new interconnections and other system modifications. For example, we are currently implementing projects that will make much of the system bi-directional, increasing the flexibility of how we operate this system. As a result of the development of laterals, interconnects, and bi-directional capability, we now have access to multiple strategic natural gas supply sources, including supplies on the Gulf Coast, basins in North Texas (Barnett Shale), East Texas, North Louisiana, the Marcellus and Utica regions, and the Appalachian Basin. Similarly, through interconnections with major interstate and intrastate pipelines, we also access large and growing markets in the northeast, midwest, mid-Atlantic and southeast U.S., and serve industrial, commercial, electric generation and residential customers in various states within our footprint.

Increasing Competition. Our pipeline systems compete primarily with other interstate and intrastate pipelines. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, at least in particular supply or market areas where we serve, and the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term basis, our revenues are not significantly affected by variation in customers’ actual usage resulting from increased competition during the near term. Our ability to remarket the capacity as our contracts expire may be impacted by increased competition.

Regulatory Compliance. Regulation of natural gas transportation by the FERC and other federal and state regulatory agencies, including DOT has a significant impact on our business. For example, the Pipeline and Hazardous Materials Safety Administration, or PHMSA, office of the DOT has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. The FERC regulatory policies govern the rates and services that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates PCBs at specific gas transmission facilities pursuant to the AOC and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs will cease on January 31, 2015. As of September 30, 2014, Columbia Gas Transmission has recorded $2.8 million to cover costs associated with PCB remediation related to this AOC. The cost of this PCB remediation is not expected to have a material adverse impact on our financial condition, results of operations or ability to make distributions to our unitholders.

 

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Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of natural gas and therefore throughput on our assets. For more information see “Business—FERC Regulation” and “Business—Pipeline Safety and Maintenance.”

Cost Recovery Trackers and other similar mechanisms. Under section 4 of the Natural Gas Act, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect.

Due to these trackers, a significant portion of our revenues and expenses are related to the recovery of these costs. The costs that are being recovered are reflected in revenue and are offset in expenses. These costs include: third-party transportation, electric compression, environmental, and the net expense associated with certain approved operational purchases and sales of natural gas.

Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel.

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:

 

   

Revenues and contract mix, particularly the level of firm capacity subscribed;

 

   

Operating expenses; and

 

   

Adjusted EBITDA.

Revenue Contract Mix and Volumes. Our results are driven primarily by the volume of natural gas transportation and storage capacity under firm and interruptible contracts, the volume of natural gas that we gather and transport, and the fees assessed for such services, as well as fees derived from royalties. One of our primary financial goals is to maximize the portion of our physical transportation and storage capacity that is contracted under multi-year firm contracts in order to enhance the stability of our revenues and cash flows. We provide a significant portion of our transportation and storage services through firm contracts and derive a small portion of our revenues through interruptible service contracts. To the extent that physical capacity that is contracted by firm service customers is not being fully utilized or there is excess capacity that is not contracted for firm service, we can offer such capacity to interruptible service customers.

Transmission and Storage. Firm transportation service allows the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly charge to reserve an agreed-upon amount of pipeline capacity regardless of the actual pipeline capacity used by the customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transportation customer uses the capacity it has reserved under these firm transportation contracts. Usage charges are assessed on the actual volume of natural gas transported on the transportation system. In addition, firm transportation customers are charged an overrun usage charge when the level of natural gas received for delivery from a firm transportation customer exceeds its reserved capacity.

Firm storage contracts obligate our customers to pay a fixed monthly reservation charge for the right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges for the actual quantities of natural gas injected into or withdrawn from storage.

 

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We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices.

For the year ended December 31, 2013, approximately 93.1% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 5.0% of the transportation and storage revenues were derived from usage fees under firm contracts compared to 91.4% and 5.7%, respectively, for the year ended December 31, 2012. For the nine months ended September 30, 2014, approximately 93.8% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 4.3% of the transportation and storage revenues were derived from usage fees under firm contracts compared to approximately 92.9% and 5.3%, respectively, for the nine months ended September 30, 2013.

Interruptible transportation and storage service is typically less than a year and is generally used by customers that either do not need firm service, have been unable to contract for firm service or require transportation volumes in excess of their contracted firm service. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. The FERC-regulated transportation and storage operators are obligated to provide interruptible services only if a shipper is willing to pay the FERC-approved tariff rate. We believe that our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transportation and storage services is our natural gas ‘‘park and loan’’ services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a usage fee-based on the quantities of natural gas they store in (park), or borrow from (loan), our storage facilities.

For the years ended December 31, 2013 and 2012, approximately 1.9% and 2.9% respectively, of the transportation and storage revenues were derived from interruptible contracts. For the nine months ended September 30, 2014 and 2013, approximately 2.0% and 1.8%, respectively, of the transportation and storage revenues were derived from interruptible contracts.

Gathering and Processing. Our long-term, fee-based agreements provide for a fixed fee for one or more of the following midstream natural gas services: natural gas gathering, treating, conditioning, processing, compression and liquids handling. Under these agreements, which contain minimum volume commitment features, we are paid a fixed fee based on the volume of the natural gas that we gather and process. Under these agreements, our customers commit to ship a minimum annual volume of natural gas on our gathering system, or, in lieu of shipping such volumes, to pay us periodically as if that minimum amount had been shipped. If capacity is available on the pipeline or at the processing plant, a customer may exceed its minimum volume amounts and pay a fixed fee on the additional volumes. We also provide interruptible gathering and transportation service on our gathering pipelines to optimize our revenues on those systems.

Other Assets. We own the production rights below many of Columbia Gas Transmission’s storage facilities. Some of these production rights have been subleased to producers in return for an overriding royalty interest and upfront bonus payments. Each sublease negotiation is unique and may have additional rights or options attached to the agreement such as the option to participate as a working interest owner in drilling operations. We have also contributed our production rights in another field, Brinker storage field, to Hilcorp, and participate as a 5% working interest partner with an overriding interest in the development of a broader acreage dedication.

Operating Expenses. The primary component of our operating costs and expenses that we evaluate is operations and maintenance expenses. These expenses represent the cost of operating and maintaining our plants and equipment or the cost of running the physical systems. Operations and maintenance expenses are comprised primarily of labor, materials and supplies, outside services and other expenses. Maintenance and repairs, including the cost of removal of minor items of property, are charged to expense as incurred.

 

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We are also charged or allocated expenses from NiSource Corporate Services, a centralized service company that provides executive, financial, legal, information technology and other administrative and general services. Costs incurred for these services consist of employee compensation and benefits, outside services and other expenses. Costs are allocated using various methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures.

In the future, we expect operations and maintenance expense to also include direct and indirect costs that we will reimburse to our general partner and its affiliates pursuant to our partnership agreement and the omnibus agreement, and other expenses attributable to our status as a publicly traded partnership, such as: expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses and director compensation.

Adjusted EBITDA. We evaluate our business on the basis of Adjusted EBITDA. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks and others, to assess:

 

   

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

 

   

the ability of our assets to generate cash sufficient to make distributions to our partners;

 

   

the operating performance and return on invested capital as compared to those of other publically traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

Adjusted EBITDA is not a presentation made in accordance with GAAP and is defined differently by different companies in our industry. As such, the definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. For a reconciliation of Adjusted EBITDA to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Items Affecting Comparability of Our Financial Results

The historical financial results of the Predecessor discussed below may not be comparable to our future financial results for the following reasons:

 

   

Our Predecessor’s results of operations historically included revenues and expenses relating to 100% of NiSource’s Columbia Pipeline Group reportable segment. NiSource will not contribute Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company to Columbia OpCo. Such assets were historically included in NiSource’s Columbia Pipeline Group reportable segment, but constituted an immaterial impact on the Predecessor’s results of operations. CNS Microwave is not included in the Predecessor but will be contributed to Columbia OpCo.

 

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After the completion of this offering, we will own a 14.6% interest in Columbia OpCo rather than the 100% ownership reflected as part of the Predecessor’s historical financial results. We will control Columbia OpCo through our ownership of its general partner. Our pro forma financial statements consolidate, and our financial statements after the closing of this offering will consolidate, all of Columbia OpCo’s financial results with ours in accordance with GAAP. Consequently, our future consolidated financial statements will include Columbia OpCo as a consolidated subsidiary, and CEG’s 85.4% interest will be reflected as a non-controlling interest.

 

   

Following the completion of this offering, we estimate that we will incur $5 million of incremental annual general and administrative expenses as a result of operating as a publicly traded partnership. These incremental general and administrative expenses are not reflected in the Predecessor’s financial results and consist of expenses that we expect to incur as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

 

   

At the completion of the offering, short-term borrowings – affiliated and a portion of the long-term debt—affiliated will be transferred to an affiliate of NiSource and the related interest expense will no longer be incurred.

 

   

We have entered into a $500 million revolving credit facility, which will become effective upon the closing of this offering, that we expect will incur interest expense at customary short-term interest rates.

General Trends and Outlook.

We expect our business to continue to be affected by the following key trends. Our expectations are based on management assumptions and currently available information. To the extent management’s underlying assumptions about or interpretations of available information prove to be incorrect, actual results could vary materially from our expected results. Please read “Risk Factors.”

Benefits from System Expansions. We expect that our results of operations will benefit from increased revenues associated with the expansion projects identified under “—Factors and Trends That Impact Our Business—Growth Associated with Expansions” above. These projects have provided our customers with increased access to new sources of supply while extending their market reach. We are also continuing to pursue expansion across our footprint that will allow for the transport of constrained natural gas production in the Marcellus and Utica producing regions to areas of demand and/or to locations for conversion to LNGs for exportation off the continent. We expect that completion of these projects will increase utilization along our pipeline system.

Growth Opportunities. We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited partner interests in Columbia OpCo in connection with its issuance of any new equity interests.

Growing Markets. Our system provides upstream supply to northeast, midwestern and southern end-use markets where the EIA, in its 2014 Annual Energy Outlook, estimates natural gas consumption will grow by approximately 2.1%, 11.2%, and 11.2% respectively, between 2013 and 2023. Moreover, growth in natural gas consumption, according to EIA, is centered around growth in industrial and power growth sectors. That subset of consumption is expected to grow in the northeast, midwestern and southern markets by 4.8%, 37.7% and 14.1%, respectively.

 

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Growing LNG Export Market. Domestic dry natural gas production in the U.S. is expected to outpace domestic consumption. According to the EIA, domestic dry natural gas production is estimated to grow approximately 2.3% per year, from 24.72 quadrillion Btu in 2013 to 32.57 quadrillion Btu in 2025, while growth in U.S. natural gas demand is only estimated to grow by approximately 0.8% per year, from 26.22 quadrillion Btu in 2013 to 28.97 quadrillion Btu in 2025. The net difference between supply and demand is expected, largely, to be taken off the continent by conversion to LNG. The EIA forecasts that gross natural gas exports, including LNG exports, will increase by approximately 10.0% per year from 1.73 quadrillion Btu in 2013 to 5.45 quadrillion Btu in 2025. We believe our assets provide a unique footprint from the Marcellus and Utica regions to the Gulf of Mexico where the majority of the liquefaction facilities for LNG export have been announced, putting us in a prime position to capitalize on the LNG export market.

Results of the Predecessor’s Operations

The following schedule presents the Predecessor’s historical combined key operating and financial metrics.

 

     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2013     2012     2011     2014      2013  
     (in millions)  

Operating Revenues

           

Transportation revenues

   $ 850.9      $ 679.4      $ 678.6      $  743.5       $ 621.4   

Transportation revenues—affiliated

     94.3        96.0        96.8        66.3         65.3   

Storage revenues

     142.8        144.3        144.1        108.2         107.4   

Storage revenues—affiliated

     53.6        52.4        52.0        40.1         40.3   

Other revenues

     37.8        28.3        34.1        48.4         23.2   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Operating Revenues

     1,179.4        1,000.4        1,005.6        1,006.5         857.6   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Operating Expenses

           

Operation and maintenance

     507.1        374.2        377.9        477.1         366.7   

Operation and maintenance—affiliated

     118.1        105.6        98.3        89.6         82.4   

Depreciation and amortization

     106.9        99.3        130.0        87.7         78.9   

(Gain)/loss on sale of assets

     (18.6     (0.6     0.1        (20.8      (11.3

Property and other taxes

     62.2        59.2        56.6        50.3         46.6   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Operating Expenses

     775.7        637.7        662.9        683.9         563.3   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Equity Earnings in Unconsolidated Affiliates

     35.9        32.2        14.6        32.9         25.6   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Operating Income

     439.6        394.9        357.3        355.5         319.9   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Other Income (Deductions)

           

Interest Expense - affiliated

     (37.9     (29.5     (29.8     (39.1      (27.6

Other, net

     17.6        1.5        1.2        8.0         15.3   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Other Deductions, net

     (20.3     (28.0     (28.6     (31.1      (12.3
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Income before Income Taxes

     419.3        366.9        328.7        324.4         307.6   

Income Taxes

     152.4        136.9        125.6        119.7         112.4   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net Income

   $ 266.9      $ 230.0      $ 203.1      $ 204.7       $ 195.2   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Throughput (MMdth)

           

Columbia Gas Transmission

     1,354.3        1,305.7        1,345.7        1,023.9         998.1   

Columbia Gulf

     643.0        894.3        1,048.0        473.3         494.0   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total

     1,997.3        2,200.0        2,393.7        1,497.2         1,492.1   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Operating Revenues. Operating revenues were $1,006.5 million for the nine months ended September 30, 2014, an increase of $148.9 million from the same period in 2013. The increase in operating revenues was due primarily to

 

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increased revenue of $87.6 million attributable to recovery of operating costs under our regulatory tracker mechanisms, which is offset in expense, increased revenue of $34.1 million primarily from new winter contracts and the Warren County and West Side expansion projects and increased mineral rights royalty revenue of $20.5 million primarily attributable to increased third-party drilling activity and increased condensate revenue of $3.7 million.

Operating Expenses. Operating expenses were $683.9 million for the nine months ended September 30, 2014, an increase of $120.6 million from the same period in 2013. The increase in operating expenses was primarily due to $87.6 million of increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, increased employee and administrative expenses of $24.4 million, increased depreciation and amortization of $8.8 million primarily due to increased capital expenditures related to projects placed in service, higher outside service costs of $7.5 million and higher property taxes of $3.1 million. These increases were partially offset by higher gains on the sale of assets of $9.5 million resulting from conveyances of mineral interests of $20.8 million, offset by the sale of storage base gas in 2013 of $11.1 million. Operating expenses were further offset by lower software data conversion costs of $7.5 million. 

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $32.9 million for the nine months ended September 30, 2014, an increase of $7.3 million from the same period in 2013. Equity earnings increased primarily due to new compression assets placed into service at Millennium Pipeline.

Other Income (Deductions). Other Income (Deductions) for the nine months ended September 30, 2014 reduced income by $31.1 million compared to a reduction in income of $12.3 million in the same period in 2013. The increase in deductions was primarily due to a $12.3 million increase in interest expense resulting from $616.2 million of additional borrowings on the intercompany long-term note that originated on December 9, 2013, and a $10.5 million gain from insurance proceeds in 2013. These increases were partially offset by a $3.5 million increase in the equity portion of allowance for funds used during construction.

Income Taxes. The effective income tax rates for the nine months ended September 30, 2014 and 2013 were comparable at 36.9% and 36.5%, respectively.

Throughput for the Predecessor totaled 1,497.2 MMDth for the nine months ended September 30, 2014 compared to 1,492.1 MMDth for the same period in 2013.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Operating Revenues. Operating revenues were $1,179.4 million for 2013, an increase of $179.0 million from the same period in 2012, primarily due to increased revenue of $119.5 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense, the current period impact of the 2012 modernization settlement at Columbia Gas Transmission, which resulted in an increase in operating revenues of $50.3 million, higher revenue of $11.9 million from interim capacity on the West Side Expansion and increased mineral rights royalty revenue of $2.7 million. These increases were partially offset by lower shorter term transportation services of $7.6 million.

Operating Expenses. Operating expenses were $775.7 million for 2013, an increase of $138.0 million from the comparable period in 2012. The increase in operating expenses was primarily due to increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, of $119.5 million, higher employee and administrative expenses of $19.0 million that included $8.5 million related to higher pension costs, software data conversion costs of $8.9 million and higher depreciation and amortization of $7.6 million primarily due to increased capital expenditures related to projects placed in service. These increases were partially offset by higher gains on the sale of assets of $18.0 million resulting from the sale of storage base gas and conveyances of mineral interests.

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $35.9 million in 2013, an increase of $3.7 million compared with 2012. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline.

 

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Other Income (Deductions). Other Income (Deductions) in 2013 reduced income by $20.3 million compared to a reduction in income of $28.0 million in 2012. The decrease is primarily due to a $10.5 million gain from insurance proceeds and a $5.4 million increase in the equity portion of allowance for funds used during construction. This decrease was offset by an increase in interest expense of $8.4 million as a result of the issuance of intercompany long-term notes of $310 million in November 2012, $150 million in December 2012 and $65.1 million in December 2013.

Income Taxes. Income taxes increased $15.5 million in 2013 compared to 2012 primarily due to the increase in pre-tax income. The effective income tax rates were 36.3% and 37.3% in 2013 and 2012, respectively.

Throughput. Throughput for the Predecessor totaled 1,997.3 MMDth for 2013, compared to 2,200.0 MMDth for the same period in 2012. The colder weather, which primarily drove the increase on the Columbia Gas Transmission system, was more than offset by the impact from increased production of Appalachian shale gas that resulted in fewer deliveries being made by Columbia Gulf to Columbia Gas Transmission at Leach, Kentucky.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating Revenues. Operating revenues were $1,000.4 million for 2012, a decrease of $5.2 million from the same period in 2011. The decrease was primarily attributable to the modernization settlement at Columbia Gas Transmission, which decreased operating revenues by $81.7 million. Also contributing to the decrease was a $4.3 million decrease in condensate revenue. These decreases were partially offset by increased regulatory tracker mechanisms, which are offset in expense, of $48.6 million, a $21.9 million increase in revenue attributable to the interim capacity on the West Side Expansion project, an $8.3 million increase attributable to higher tariff rates at Columbia Gulf, and a $6.1 million increase due to shorter term transportation services.

Operating Expenses. Operating expenses were $637.7 million for 2012, a decrease of $25.2 million from the comparable period in 2011. The decrease in operating expenses was primarily due to a decrease in employee and administrative costs of $44.7 million, driven primarily by decreased pension contributions, lower depreciation and amortization of $30.7 million largely as a result of the Columbia Gas Transmission modernization settlement, and decreased environmental costs of $12.1 million primarily due to the 2011 environmental remediation liability adjustment. These decreases were partially offset by increased regulatory trackers, which are offset in operating revenues, of $48.6 million, increased outside services of $6.2 million primarily due to the timing of maintenance projects, and the write-off of capital project costs of $4.3 million.

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $32.2 million in 2012, an increase of $17.6 million compared with 2011. Equity earnings increased primarily due to increased volume and commodity revenues due to the development of backhaul flows on Millennium Pipeline.

Other Income (Deductions). Other Income (Deductions) in 2012 reduced income by $28.0 million compared to a reduction income of $28.6 million in 2011.

Income Taxes. Income taxes increased $11.3 million in 2012 compared to 2011 primarily due to the increase in pre-tax income. The effective income tax rates were 37.3% and 38.2% in 2012 and 2011, respectively.

Throughput. Throughput for the Predecessor totaled 2,200.0 MMDth for 2012, compared to 2,393.7 MMDth in 2011. The decrease of 198.7 MMDth was primarily attributable to warmer winter weather in 2012, which drove a vast majority of the decrease on the Columbia Gas Transmission system. In addition, fewer deliveries were made on the Columbia Gulf system to Columbia Gas Transmission at Leach, Kentucky because of the impact from increased production of Appalachian shale gas and the warmer winter weather. The increase in shale gas from the Appalachian, Haynesville and Barnett shale areas has also led to an increase in non-traditional throughput on Columbia Gulf in the form of deliveries to other interstate pipelines at liquid market centers on the Columbia Gulf system.

 

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Liquidity and Capital Resources

Our principal liquidity requirements are to finance our operations, fund capital expenditures and acquisitions of additional interests in Columbia OpCo, make cash distributions and satisfy our indebtedness obligations. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future. Historically, our sources of liquidity included cash generated from operations and intercompany loans from NiSource Finance, a wholly owned subsidiary of NiSource. We also participated in NiSource’s money pool administered by NiSource Corporate Services, whereby on a daily basis cash balances residing in our bank accounts are swept into a NiSource corporate account. Therefore, our historical financial statements reflect little or no cash balances.

In connection with this offering, we will establish separate bank accounts, but CEG or its affiliates will continue to provide treasury services on our general partner’s behalf under our omnibus agreement. Unlike our transactions with third parties, which ultimately settle in cash, our affiliate transactions are settled on a net basis through an intercompany receivable/payable with affiliates. Due to capital expenditures funded in this manner, these balances have accumulated over time to reflect a net payable to NiSource. Prior to the completion of this offering, CEG will assume the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and NiSource Finance will novate the $1.2 billion of intercompany debt from the subsidiaries to CEG.

Subsequent to this offering, we expect our sources of liquidity to include:

 

   

cash generated from our operations;

 

   

$500 million available for borrowing under our credit facility;

 

   

cash distributions received from Columbia OpCo;

 

   

issuances of additional partnership units;

 

   

debt offerings;

 

   

$750 million of reserved borrowing capacity under an intercompany money pool initially with NiSource Finance in which Columbia OpCo and its subsidiaries are participants; and

 

   

long-term intercompany borrowings.

We believe that cash on hand, cash generated from operations and availability under our credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements, and our cash distribution requirements. We believe that future internal growth projects or potential acquisitions of additional interests in Columbia OpCo will be funded primarily through borrowings under our credit facility or through issuances of debt and equity securities.

All of our cash will be generated from cash distributions from Columbia OpCo. Columbia OpCo will be a restricted subsidiary and a guarantor under our credit facility and the bank syndicated credit facility available to HoldCo. In connection with the spin-off, HoldCo expects to issue a significant amount of new senior indebtedness. Under the omnibus agreement, at HoldCo’s request Columbia OpCo will guarantee future indebtedness of HoldCo. To the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant restrictions on Columbia OpCo’s operations which, in turn, may limit its ability to finance future business opportunities and make cash distributions to us. Please read “Risk Factors—Risk Inherent in Our Business—Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.”

 

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Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

Changes in the terms of our transportation arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

Cash Flow. Net cash from operating activities, net cash used for investing activities and net cash from (used for) financing activities for the years ended December 31, 2013, 2012 and 2011, and for the nine months ended September 30, 2014 and 2013, were as follows:

 

     For the Years Ended
December 31,
    For the Nine Months Ended
September 30,
 
     2013     2012     2011         2014             2013      
     (in millions)  

Net cash from operating activities

   $ 454.0      $ 474.9      $ 435.3      $ 446.6      $ 316.5   

Net cash used for investing activities

   $ (797.4   $ (455.5   $ (307.2   $ (618.6   $ (527.6

Net cash from (used for) financing activities

   $ 343.1      $ (18.8   $ (128.1   $ 172.1      $ 210.6   

Operating Activities

Net cash from operating activities for the nine months ended September 30, 2014 was $446.6 million, an increase of $130.1 million from the prior year. The increase in net cash from operating activities was primarily due to an increase in customer deposits related to growth projects and changes in regulatory assets and liabilities related to the refund for the Columbia Gas Transmission customer settlement in the prior year.

Net cash from operating activities for the year ended December 31, 2013 was $454.0 million, a decrease of $20.9 million from a year ago. The decrease in net cash from operating activities was primarily due to a decrease in working capital due to changes in the funded status of the postretirement and postemployment benefits obligation partially offset by an increase in working capital from income tax receivables of $27.4 million primarily due to a refund from the IRS received in 2013.

Net cash from operating activities for the year ended December 31, 2012 was $474.9 million, an increase of $39.3 million from the prior year. The increase in net cash from operating activities was primarily due to pension and postretirement contributions of $81.8 million in 2011 compared to $10.3 million in 2012 and an increase in distributions from equity investees of $16.1 million. These increases in cash flows from operating activities were offset by an increase in cash paid for income taxes under the NiSource tax sharing arrangement of $63.6 million.

Investing Activities

The table below reflects actual expansion and maintenance capital expenditures by category for years ended December 31, 2013, 2012 and 2011 and estimates for 2014 and nine months ended September 30, 2014 and 2013.

 

     Year Ended December 31,      Nine Months Ended
September 30,
 
     2014E      2013      2012      2011      2014      2013  
     (in millions)  

Expansion - modernization, system growth, and equity investments

   $ 675.0       $ 664.8       $ 280.0       $ 81.5       $ 536.3       $ 476.2   

Maintenance

     132.3         132.7         209.6         220.0         90.1         80.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(1)

   $ 807.3       $ 797.5       $ 489.6       $ 301.5       $ 626.4       $ 556.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

 

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(1) The difference between total capital expenditures in this table and the capital expenditures line item on our statement of cash flows primarily consists of (i) contributions to equity investees, (ii) the non-cash change in capital expenditures included in current liabilities, (iii) the non-cash change in working interest payable and (iv) non-cash AFUDC equity.

Capital expenditures for the Predecessor for the nine months ended September 30, 2014 increased by $69.9 million compared to the same period in 2013 primarily due to the modernization program and system growth and equity investments in the Marcellus and Utica shale areas.

Capital expenditures for the Predecessor in 2013 increased by $307.9 million compared to 2012 due to the modernization program and system growth and equity investments in the Marcellus and Utica shale areas. Capital expenditures for 2012 were higher than 2011 by approximately $188.1 million due to system growth in the Marcellus shale area.

The capital expenditure program and other investing activities in 2014 are projected to be approximately $807.3 million (cost to Columbia OpCo). The projected 2014 expenditures are comprised of (i) a current profile of identified growth projects and (ii) modernization and maintenance expenditures.

Financing Activities

Net cash from financing activities for the nine months ended September 30, 2014 was $172.1 million, a decrease of $38.5 million from the prior year. The decrease in net cash from financing activities was due to a decrease in short term borrowings from the money pool offset by additional borrowings on the intercompany long-term note that originated on December 9, 2013.

Net cash from financing activities for the year ended December 31, 2013 was $343.1 million, an increase of $361.9 million from a year ago. The increase in net cash from financing activities was due to an increase in short-term borrowings from the NiSource money pool to fund capital expenditures.

Net cash used for financing activities for the year ended December 31, 2012 was $18.8 million, a decrease of $109.3 million from the prior year. The decrease in net cash used for financing activities was due to an increase in short-term borrowings from the money pool to fund capital expenditures.

Columbia Pipeline Partners Credit Agreement. On December 5, 2014, we entered into a $500 million senior revolving credit facility, which will become effective upon the closing of this offering and of which $50 million will be available for the issuance of letters of credit. We expect to have no borrowings upon the closing of this offering. We expect that the credit facility will be available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls.

We expect that our obligations under the revolving credit facility will be unsecured, however, if the credit rating of HoldCo at the time of the spin-off is not BB+ or better and Ba1 or better, then we may be required to post collateral to secure our obligations under the revolving credit facility. The loans thereunder shall bear interest at our option at either (i) the greatest of (a) the federal funds effective rate plus 0.50 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of HoldCo, once NiSource is released as a guarantor from our revolving credit facility, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of HoldCo, once NiSource is released as a guarantor from our revolving credit facility. The revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of HoldCo, once NiSource is released as a guarantor from our revolving credit facility.

 

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We expect that revolving indebtedness under the credit facility will rank equally with all our outstanding unsecured and unsubordinated debt. NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo will each fully guarantee the credit facility, except that NiSource shall be released from its guarantee upon receipt by HoldCo of a rating by Moody’s and S&P.

The revolving credit facility was executed on December 5, 2014 but will not become effective until the closing of this offering. Additionally, our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our and our restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by our organizational documents. If we fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. Our revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of an amount to be agreed.

The revolving credit facility also contains certain financial covenants that will require us to maintain (a) a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00 and (b) until HoldCo has received an investment grade rating, a Consolidated Interest Coverage Ratio (as defined in the revolving credit facility) of no less than 3.00 to 1.00.

Columbia OpCo Money Pool Agreement. In connection with the closing of this offering, Columbia OpCo and its subsidiaries will enter into an intercompany money pool agreement initially with NiSource Finance and, following the spin-off, with HoldCo with $750 million of reserved borrowing capacity, which will be undrawn upon the closing of this offering. We expect that the money pool will be available for its general partnership purposes, including capital expenditures and working capital.

In furtherance of the money pool arrangement, HoldCo has entered into a $1,500 million senior revolving credit facility, which will become effective at the time of the spin-off, and of which $750 million will be utilized as credit support for Columbia OpCo and its subsidiaries in connection with the money pool arrangement. Otherwise, HoldCo expects that its credit facility will be available for its general corporate purposes, including working capital.

We expect that the obligations of HoldCo under its revolving credit facility will be unsecured, however, if the credit rating of Holdco at the time of the spin-off is not BB+ or better and Ba1 or better, then we may be required to post collateral to secure our obligations under the revolving credit facility. Each of CEG, OpCo GP and Columbia OpCo is a guarantor of HoldCo’s revolving credit facility. The loans thereunder shall bear interest at HoldCo’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.50 percent, (b) the reference prime rate of JPMorgan Chase Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of HoldCo, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of Holdco. HoldCo’s revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of HoldCo.

 

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HoldCo’s revolving credit facility was executed on December 5, 2014 but will not become effective until the completion of the spin-off. Additionally, as a guarantor and restricted subsidiary, Columbia OpCo is subject to various customary covenants and restrictive provisions which, among other things, limit HoldCo’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. If Columbia OpCo fails to perform its obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. HoldCo’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness HoldCo may have with an outstanding principal amount in excess of an amount to be agreed.

HoldCo’s revolving credit facility also contains certain financial covenants that will require HoldCo to maintain (a) a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in HoldCo’s revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00 and (b) until HoldCo has received an investment grade rating, a Consolidated Interest Coverage Ratio (as defined in HoldCo’s revolving credit facility) of no less than 3.00 to 1.00.

In addition, a breach by HoldCo of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against Columbia OpCo as a guarantor.

Contractual Obligations. The Predecessor has certain contractual obligations requiring payments at specified periods. The obligations include long-term debt-affiliated, lease obligations and service obligations for pipeline service agreements. The total contractual obligations in existence at December 31, 2013 and their maturities were:

 

     Total      2014      2015      2016      2017      2018      After  
     (in millions)  

Long-term debt-affiliated

   $ 819.8       $ —         $ 115.9       $ 110.4       $ —         $ —         $ 593.5   

Interest payments on long-term debt

     751.8         43.5         43.0         37.0         31.7         31.7         564.9   

Pipeline transportation capacity agreements

     199.5         37.6         36.0         31.0         21.4         17.9         55.6   

Operating leases(1)

     17.7         4.2         2.6         2.3         2.1         1.8         4.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 1,778.8       $ 85.3       $ 197.5       $ 180.7       $ 55.2       $ 51.4       $ 1,218.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Operating lease expense for 2013 was $13.4 million, which includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.

The Predecessor’s long-term financing requirements are satisfied through borrowings from NiSource Finance.

The Predecessor has third-party transportation agreements that provide for transportation and storage services. These agreements, which have expiration dates ranging from 2014 to 2024, require the Predecessor to pay fixed monthly charges and allow the Predecessor to use third-party transportation as operationally needed. Most of these costs are eligible to be collected through a FERC approved regulatory tracker from the Predecessor’s shippers.

 

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The Predecessor continued to borrow on the intercompany long-term note that originated on December 9, 2013 in the nine months ended September 30, 2014. The following table summarizes the maturity of long-term debt—affiliated at September 30, 2014:

 

     Total      2014      2015      2016      2017      2018      After  
     (in millions)  

Long-term debt—affiliated

   $ 1,370.9       $ —         $ 115.9       $ 661.5       $ —         $ —         $ 593.5   

Interest payments on long-term debt

     830.3         69.7         69.1         63.2         31.7         31.7         564.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 2,201.2       $ 69.7       $ 185.0       $ 724.7       $ 31.7       $ 31.7       $ 1,158.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

There were no material changes recorded during the nine months ended September 30, 2014 to the Predecessor’s pipeline transportation capacity agreements and operating lease contractual obligations as of December  31, 2013.

Critical Accounting Policies

We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on results of operations and the combined balance sheet.

Basis of Accounting for Rate-Regulated Subsidiaries. ASC Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Combined Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Combined Balance Sheets were $142.6 million and $283.1 million at December 31, 2013, and $232.0 million and $343.1 million at December 31, 2012, respectively. For additional information, refer to Note 8, “Regulatory Matters,” in the Predecessor’s audited Notes to Combined Financial Statements and Note 7, “Regulatory Matters,” in the Predecessor’s Notes to Condensed Combined Financial Statements (unaudited).

In the event that regulation significantly changes the opportunity for us to recover its costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated companies will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.

No regulatory assets are earning a return on investment at December 31, 2013. Regulatory assets of $25.6 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 30 years.

Pensions and Postretirement Benefits. NiSource has defined benefit plans for both pensions and other postretirement benefits that cover the employees of Columbia OpCo. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of NiSource’s pensions and other postretirement benefits, see Note 11, “Pension and Other Postretirement Benefits,” in the Predecessor’s audited

 

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Notes to Combined Financial Statements and Note 10, “Pension and Other Postretirement Benefits,” in the Predecessor’s Notes to Condensed Combined Financial Statements (unaudited).

Goodwill. In accordance with the provisions for goodwill accounting under GAAP, we test our goodwill for impairment annually as of May 1 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB. Columbia Gas Transmission Operations has been determined to be a reporting unit. Our goodwill assets at September 30, 2014, December 31, 2013 and 2012 were approximately $2.0 billion pertaining to the acquisition of Columbia Energy Group on November 1, 2000.

We completed a quantitative (“step 1”) fair value measurement of our reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed under the step 1 annual impairment test. For 2013 and 2014, a qualitative (“step 0”) test was performed as of May 1 of each respective period. We assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units in its baseline May 1, 2012 test. The results of this assessment indicated that it is not more likely than not that its reporting unit fair values are less than the reporting unit carrying values and no impairments are necessary.

Although there was no goodwill asset impairment as of May 1, 2014, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, or if our market capitalization stays below book value for an extended period of time. No impairment triggers were identified subsequent to May 1, 2014.

Refer to Notes 1-I and 6, “Goodwill” in the Predecessor’s audited Notes to Combined Financial Statements for additional information and Note 5, “Goodwill,” in the Predecessor’s Notes to Condensed Combined Financial Statements (unaudited).

Revenue Recognition. Revenue is recognized as services are performed. Revenues are billed to customers monthly at maximum rates established through the FERC’s cost-based rate-making process, though customers with negotiated rate agreements or discount rates may pay rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.

The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.

We provide shorter term transportation services, for which cash is received at inception of the service period and is recorded as deferred revenue and recognized as income over the period the services are provided.

Revenues from storage are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

Deferred revenue includes a gain on conveyances related to pooling of assets (production rights) in a joint undertaking intended to find, develop, or produce oil or gas from a particular property or group of properties. The gain was initially deferred as we have a substantial obligation for future performance. As the obligation for future performance is satisfied the deferred revenue is relieved and the associated gain is recognized.

 

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The Predecessor includes the subsidiary CEVCO, which owns the mineral rights to over 450,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $21.2 million, $18.5 million and $14.5 million for the years ended December 31, 2013, 2012, and 2011, respectively, and are included in “Other revenues” on the Combined Statement of Operations.

Recently Issued Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We will be required to adopt ASU 2014-09 for periods beginning after December 15, 2016, including interim periods, and is to be applied retrospectively with early adoption not permitted. We are currently evaluating the impact the adoption of ASU 2014-09 will have on our Combined Financial Statements and Notes to Combined Financial Statements.

In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that represents a strategic shift that has or will have a major impact on its operations and financial results is a discontinued operation. We will be required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. We are currently evaluating what impact, if any, adoption of ASU 2014-08 will have on our Combined Financial Statements and Notes to Combined Financial Statements.

Qualitative and Quantitative Disclosures About Market Risk

Risk is an inherent part of our business. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to its profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal risks that are involved in our businesses: commodity market risk, interest rate risk and credit risk. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These include but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of our business, risk management processes, policies and procedures continue to evolve and are subject to ongoing review and modification.

Commodity Price Risk. Other than the base gas purchased and used in the natural gas storage facilities, which is necessary to maintain pressure and deliverability in the storage pools, we generally do not take title to the natural gas that we store and/or transport for customers and, accordingly, we are not exposed to commodity price fluctuations on natural gas stored in our facilities or transported through our pipelines by our customers. Base gas purchased and used in natural gas storage facilities is considered a long-term asset and is not re-valued at current market prices. A certain amount of gas is naturally lost in connection with transporting natural gas across our pipeline system and, under our contractual arrangements with our customers, we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as our fuel usage. Except for the base gas in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to the volumes of fuel we purchase to make up for line loss, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas over the intermediate term should not materially impact our operations. We have not historically engaged in material commodity hedging

 

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activities relating to our assets. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.

Interest Rate Risk. We are exposed to interest rate risk as a result of changes in interest rates on borrowings under its intercompany term loans, which have fixed and variable interest rates. The Predecessor entered into a variable interest term loan with NiSource Finance which carries an interest rate of prime plus 150 basis points. As of September 30, 2014, the outstanding balance on this term loan was $616.2 million. An increase or decrease of 100 basis points in interest rate would result in $6.2 million change in annual interest expense. We monitor market debt rates to identify the need to mitigate this risk.

Credit Risk. Due to the nature of the industry, credit risk is embedded in our business activities. Our extension of credit is governed by NiSource’s Corporate Credit Risk Policy. In addition, NiSource’s Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by NiSource’s Corporate Credit Risk function which is independent of operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. Exposure to credit risk is measured in terms of current obligations net of any posted collateral such as cash, letters of credit and qualified guarantees of support.

Off Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

 

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INDUSTRY OVERVIEW

Natural gas is a critical and growing component of energy consumption in the U.S. The U.S. natural gas pipeline grid is the link between upstream exploration and production activities and downstream end-use markets. This network is a highly integrated transmission and distribution grid that transports natural gas from producing regions to customers such as LDCs, industrial users and electric generation facilities. Companies generate revenues at various stages within this value chain by gathering, processing, treating, fractionating, transporting, storing and marketing natural gas and NGLs.

The following diagram illustrates various components of the natural gas value chain:

 

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Source: EIA, Annual Energy Outlook 2014

The range of services offered are generally classified in to the categories described below.

Gathering. At the initial stages of the midstream value chain, a network of pipes known as gathering systems directly connect to wellheads in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which enables more efficient gathering and delivery into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Compression is also used in the transportation of natural gas to support the movement of gas across pipeline systems and in storage to enhance withdrawal and injection capability.

Treating and Dehydration. Treating and dehydration involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines.

 

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Processing. The principal components of natural gas are methane and ethane, but some natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, which increase Btu levels beyond transport specifications. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components. However, NGLs are also valuable commodities once removed from the natural gas stream and utilized in the refining and petrochemical industries. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-user sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.

Transportation. The U.S. natural gas pipeline grid transports natural gas from producing regions to customers, such as LDCs, industrial users and electric generation facilities. The concentration of natural gas production in a few regions of the U.S. generally requires transportation pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

Storage. Natural gas storage plays a vital role in maintaining the reliability of natural gas supplies needed to meet the demands of consumers. Natural gas is typically stored in underground storage facilities, including salt dome caverns and depleted reservoirs. Storage facilities are generally utilized by (1) pipelines, to manage imbalances in operations, (2) natural gas end-users, such as LDCs, to manage the seasonality and variability of demand and to satisfy future natural gas needs and (3) independent natural gas marketing and trading companies in connection with the execution of their trading strategies.

Transportation and Storage Services Contractual Arrangements

There are two basic forms of service provided in the transportation and storage of natural gas, as described below.

Firm. Firm transportation service obligates customers to pay a reservation charge for reserving an agreed upon amount of pipeline capacity, regardless of the actual pipeline capacity used, and a usage charge when a customer uses the capacity it has reserved under these firm transmission contracts. In addition, firm service transmission customers are typically charged an overrun usage charge when the level of natural gas they deliver exceeds their reserved capacity. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal usage charge based on the volumes actually injected or withdrawn relative to their total reserved capacity. In addition, firm service storage customers are typically charged an overrun usage charge when the level of natural gas withdrawn exceeds a customer’s maximum daily withdrawal limit.

Interruptible. Interruptible transportation and storage service is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers are assessed a usage fee for the volume of natural gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm service customers. Unlike customers receiving firm services, customers receiving services under interruptible contracts are not guaranteed capacity on the pipeline or at the storage facility.

 

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U.S. Natural Gas Market Fundamentals

As indicated in the charts shown below, U.S. natural gas production and overall U.S. energy demand are expected to grow in the coming decades. Population is a large determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. The EIA anticipates the total U.S. population will increase by approximately 21% from 2012 to 2040. Another important contributor to energy consumption is the industrial sector. The EIA estimates that total consumption in this sector will grow to approximately 38.3 quadrillion Btu in 2040 compared to 30.5 quadrillion Btu in 2012. Additionally, energy use is projected to grow by approximately 12% from 2012 to 2040, while energy use per capita is expected to decline by approximately 8% over the same period. A review of other supply and demand elements follows.

Natural gas is a key component of energy consumption within the U.S. According to the EIA, annual consumption of natural gas in the U.S. increased from approximately 24.9 quadrillion Btu in 2011 to approximately 26.0 quadrillion Btu in 2012. The EIA estimates that natural gas consumption represented approximately 27% of total energy consumption in 2012, and projects that this percentage will increase to approximately 30% by 2040. The charts shown below illustrate energy consumption by fuel source in 2012 and expected energy consumption by fuel source in 2040.

Energy Consumption by Fuel Source

 

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Source: EIA, Annual Energy Outlook 2014

The EIA expects that the growth of natural gas consumption relative to other fuel sources will be primarily driven by the use of natural gas electricity generation. According to the EIA, demand for natural gas in the electric power sector is projected to increase from approximately 9.3 Tcf in 2012 to approximately 11.2 Tcf in 2040, with a portion of the growth attributable to the retirement of 50 gigawatts of coal-fired capacity by 2021. The EIA also projects that natural gas consumption in the industrial sector will be higher due to the rejuvenation of the industrial sector as it benefits from surging shale gas production that is accompanied by slow price growth, particularly from 2011 through 2019, when the price of natural gas is expected to remain below 2010 levels. However, the EIA expects growth in natural gas consumption for power generation and in the industrial sector to be partially offset by decreased usage in the residential sector.

 

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U.S. Primary Energy Consumption by Fuel, 1980-2040

 

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Source: EIA, Annual Energy Outlook 2014

Over the past several years, there has been a fundamental shift in U.S. natural gas production towards unconventional sources, which according to the EIA include natural gas produced from shale formations, tight gas and coal beds. The emergence of unconventional natural gas plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale gas production. As indicated by the diagram below, the development of these unconventional resources has offset declines in other, more traditional U.S. natural gas supply sources, which has helped meet growing consumption and lowered the need for imported natural gas. In fact, the EIA predicts that the U.S. will become a net exporter of natural gas starting in 2018.

As indicated by EIA forecasts shown in the diagram below, as the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. In fact, the EIA estimates that natural gas production from the major shale formations will provide the majority of the growth in domestically produced natural gas supply in coming years, increasing to over 50% in 2040 as compared with 40% in 2012.

 

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U.S. Dry Natural Gas Production by Source, 1990-2040

 

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Source: EIA, Annual Energy Outlook 2014

LNG Market Opportunity

International natural gas reserves and production are spread over a wide array of geographic areas and the disparity between areas of production and areas of consumption has been the principal stimulus of international trade in gas. LNG is natural gas that has been converted into its liquid state through a cooling process, which allows for efficient transportation by sea. Since 2000, global LNG demand has risen, on average, 7.6% per year.

With the increased U.S. production of natural gas, U.S. domestic gas production now exceeds domestic gas consumption for a large part of the year, which may reduce future gas imports. As a result, the North American gas market is moving in a different cycle from the rest of the world and has larger differentials in pricing than other markets (see the following chart). Regional price differentials create the opportunity for arbitrage and also act as a catalyst for the extraction of new reserves. Given these conditions, interest in exporting LNG from the U.S. has grown and a number of new liquefaction plants are now planned.

 

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Natural Gas Prices, September 2009—September 2014 (U.S. $ per Mbtu)

 

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Source: Bloomberg

Overview of the Marcellus and Utica Shales

According to an ICF study from June 2014, gas production for the Marcellus and Utica shales is projected to grow to 34 MMDth/d by 2035. This figure has increased significantly from ICF’s prior forecast of 25 MMDth/d. ICF further notes, that Utica wells are “more gassy” than initially expected; therefore, gas production growth from the Utica wells is expected to be greater. Improvements in drilling and hydraulic fracturing technology continue to increase estimated ultimate recovery (“EUR”) per well. Recent well statistics reported by producers suggest that newer wells have longer horizontal laterals and more fracture stages. Gas EUR in Marcellus is projected to average 6.2 MMDth and the gas EUR in Utica is projected to average 3.3 MMDth per well. ICF experts also project more well completions because of improvements in the number of wells drilled per rig. The number of gas well completions is projected to average 2,050 wells per year in the Marcellus shale and 500 wells per year in the Utica shale through 2035.

 

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BUSINESS

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. Our business and operations will be conducted through Columbia OpCo, a recently formed partnership between CEG and us. At the completion of this offering, our assets will consist of a 14.6% limited partner interest in Columbia OpCo, as well as the non-economic general partner interest in Columbia OpCo. Through our ownership of Columbia OpCo’s general partner, we will control all of Columbia OpCo’s assets and operations.

Columbia OpCo owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2013, 93% of Columbia OpCo’s revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years.

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited partner interests in Columbia OpCo in connection with its issuance of any new equity interests.

The following is a summary of the locations and timing of our modernization program and planned growth projects:

 

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(1) 

Represents the portion of the total project cost expected to be incurred prior to the in service date.

(2) 

The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

 

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Spin-off

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo, which is expected to have an investment grade rating. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions. There is no assurance that the spin-off will in fact occur or that HoldCo will receive an investment grade rating. In the event the spin-off does occur, HoldCo will continue to indirectly own our general partner, 85.4% of the limited partner interests in Columbia OpCo and the limited partnership interests in us that are not owned by the public. Even if the spin-off is not consummated, we expect our future involvement with NiSource will be principally conducted through CEG, our sponsor.

Successful completion of the spin-off could impact our business and operations in a number of ways, including the following:

 

   

NiSource has publicly stated that the spin-off will enable both NiSource and HoldCo to execute on their distinct business strategies. Their respective businesses have different financial and operating characteristics and, as a result, different operating strategies in order to maximize their long-term value. The spin-off is expected to enable HoldCo to focus managerial attention solely on its businesses and strategies, which include our pipeline, midstream and storage business and operations. Our growth strategy requires significant capital, and if the spin-off occurs, we will no longer need to compete for capital with other NiSource businesses.

 

   

HoldCo and CEG will face the possibility of reduced financial resources and less diversification of revenue sources, which could impact our access to financial support from HoldCo and CEG.

 

   

The credit and business risk profiles of HoldCo may be factors considered in credit evaluations of us and, thus, may affect our cost of capital. For example, NiSource, which has an investment grade rating, will guarantee our credit facility upon closing of the offering. However, NiSource will be released as a guarantor on the date on which HoldCo receives a credit rating. If HoldCo is not rated investment grade, then the cost of capital under our credit facility would increase. Holdco is expected to have investment grade credit ratings following the spin-off, but there is no assurance that this will occur. Another factor that may be considered is the financial condition of HoldCo, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness.

 

   

Neither we nor Columbia OpCo will have any employees, and we will rely on CEG and its affiliates, including HoldCo, to provide us with employee services. CEG and our general partner may experience difficulty in recruiting and retaining senior management, since we will be part of a smaller enterprise following the proposed spin-off. The inability to recruit and retain these individuals could adversely affect our business and future operating results. In addition, we will lose access to the expertise of members of senior management that remain employees of NiSource after the spin-off.

 

   

As a stand-alone public company, HoldCo will be able to offer equity compensation programs that are more aligned with our business than NiSource equity compensation programs. Such equity compensation programs will help CEG and its affiliates, including HoldCo, to recruit and retain employees.

 

   

HoldCo will be implementing new accounting and other software systems to enable it to operate as a separate public company. Any delays or difficulties in implementing these systems could adversely impact our business and operations. In addition, in order to operate as a stand-alone public company, HoldCo will incur additional legal, accounting, compliance and other expenses that it has not historically incurred and that may total more than the amount of such expenses that NiSource has historically allocated to HoldCo. We will bear a portion of these increased expenses.

 

   

Under the omnibus agreement with CEG, we will agree to refrain from taking any actions that could cause HoldCo to violate its covenants under the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. Under such tax sharing agreement, HoldCo will likely agree

 

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to take action, or refrain from taking action, to ensure that the spin-off qualifies for tax-free status under Section 355 of the Code. HoldCo will also enter into various other covenants in the tax sharing agreement intended to ensure the tax-free status of the spin-off. These covenants may restrict HoldCo’s ability to sell assets outside the ordinary course of business, to issue or redeem common stock or other securities, or to permit its subsidiaries to do so. For example, subject to certain limited exceptions, HoldCo is expected to agree that, for the two years following the spin-off, HoldCo will not permit CEG to enter into a transaction that would result in CEG no longer owning our general partner or that would result in CEG owning less than 55% of Columbia OpCo. Furthermore, HoldCo is expected to agree that, for the two-year period following the spin-off, HoldCo will not permit us to enter into a transaction that would result in our ceasing to own the general partner of Columbia OpCo or to permit Columbia OpCo to dispose of business assets relied upon to satisfy the “active trade or business” requirement of Section 355 of the Code relating to the spin-off. Accordingly, we expect to refrain from taking any actions that would cause HoldCo to violate one of these or other covenants in the tax sharing agreement. As a result, our business opportunities and plans may be adversely impacted.

Business Strategies

Our principal business objective is to increase the quarterly cash distribution that we pay to our unitholders over time while ensuring the ongoing stability of our cash flows. We expect to achieve this objective through the following business strategies:

Capitalize on organic expansion opportunities. Our assets are strategically located within close proximity to growing production from the Marcellus and Utica shales and growing demand centers, providing us with substantial organic expansion opportunities. We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $4.9 billion for identified projects that we expect will be completed by the end of 2018. We intend to leverage our management team’s expertise in constructing, developing and optimizing our assets in order to increase and diversify our customer base, increase natural gas supply on our system and maximize volume throughput.

Increase our ownership interest in Columbia OpCo. We intend to increase cash flows by increasing our ownership interest in Columbia OpCo over the next several years pursuant to our preemptive right to purchase any newly issued equity interests in Columbia OpCo. We expect Columbia OpCo to issue a significant amount of new equity interests over the next several years to fund approximately $4.9 billion in estimated capital costs for organic growth projects that we expect will be completed by the end of 2018, and we expect to exercise our preemptive right to purchase these newly issued equity interests to the extent we have financing available. We also have a right of first offer with respect to acquiring CEG’s retained 85.4% limited partner interest in Columbia OpCo if CEG decides to sell such interest. We do not expect to have the ability to exercise this right in the near term.

Maintain and grow stable cash flows supported by long-term, fee-based contracts. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio to minimize our direct commodity price exposure. We will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications. Substantially all of the $4.9 billion in estimated capital costs for organic growth projects that we expect Columbia OpCo to complete by the end of 2018 are supported by long-term service contracts and binding precedent agreements.

Target a conservative and flexible capital structure. We intend to target credit metrics consistent with the profile of investment grade midstream energy companies although we do not expect to immediately seek a rating on our debt. Furthermore, we intend to maintain a balanced capital structure while financing the capital required to (i) contribute substantially all of the capital required to finance Columbia OpCo’s organic expansion projects, (ii) increase our ownership interest in Columbia OpCo and (iii) pursue potential third-party acquisitions.

 

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Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

Strategically-located assets. As a result of the geographic location of our operations, we are uniquely positioned to capitalize on both the growing natural gas production volumes in the Marcellus and Utica shales and the increasing demand for transportation, storage and related midstream services from new and existing customers. In addition, our assets provide a unique footprint from the Marcellus/Utica region to the Gulf of Mexico, where the majority of the natural gas liquefaction facilities for LNG export have been announced, positioning us to capitalize on the growing LNG export market.

Integrated service offerings, providing increased revenue opportunities. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, processing, compression, transportation and storage. Our ability to move producers’ natural gas and NGLs from the wellhead to market allows us to earn revenue from multiple services related to a single supply of natural gas and take advantage of incremental revenue opportunities that present themselves along the value chain. Providing multiple services benefits us in attracting new customers while providing us with a better understanding of each customer’s needs and the marketplace. In addition, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers’ demand for natural gas. We believe the integrated nature of our operations and the broad range of services we provide to customers allows us to compete effectively with other pipeline, storage and midstream companies that operate in our marketplace.

Stable and predictable cash flows. We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices. For the year ended December 31, 2013, approximately 93% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2013, these contracts had a weighted average remaining contract life of 5.2 years. Furthermore, a significant portion of our cash flows are generated from contracts with creditworthy customers including LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters.

Financial flexibility to pursue growth opportunities. We have entered into a new $500 million credit facility, which will become effective at the closing of this offering and is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility. This facility, which will initially be undrawn, when combined with our expected ability to access the capital markets, should enable us to fund our organic capital investment projects, purchases of additional equity in Columbia OpCo and third-party acquisitions.

Our relationship with our Sponsor. Our relationship with CEG provides us with access to CEG’s extensive operational and commercial expertise. CEG owns our general partner, a majority of our limited partner interests and all of our IDRs, as well as a retained 85.4% limited partner interest in Columbia OpCo. As a result of these ownership interests, we believe that CEG is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.

Experienced management team with a proven record of asset operation, construction, development and integration expertise. Our management team has an average of approximately 25 years of experience in the energy industry and a proven record of successfully managing, operating, developing, building, acquiring and integrating transportation, storage and other midstream assets. Our management team has established strong relationships with producers, marketers, LDCs and other end-users of natural gas throughout the upstream and midstream industries, which we believe will be beneficial to us in pursuing organic expansion opportunities. Our management team is also committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe our management team provides us with a strong foundation for evaluating growth opportunities and maintaining the integrity and efficiency of Columbia OpCo’s assets and operations.

 

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Our Relationship with Our Sponsor

One of our principal strengths is our relationship with CEG. CEG was originally formed as a Delaware corporation in 1926 and, since its acquisition by NiSource in 2000, has owned and operated substantially all of the natural gas transmission and storage assets of NiSource. CEG’s Columbia Pipeline Group has achieved a brand name in the energy infrastructure industry and developed strong relationships with producers, marketers and other end-users of natural gas throughout the upstream and midstream industries. In addition, over the past five years, CEG has implemented internal expansion capital projects totaling over $1.3 billion, of which approximately $1.1 billion was invested over the 2010 to 2013 period. We intend to utilize the significant experience of CEG’s management team to execute our growth strategy, including the construction, development and integration of additional energy infrastructure assets. NiSource is a publicly traded energy holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the midwest to New England.

Following the completion of this offering, CEG will own our general partner, 6,811,398 of our common units, all of our subordinated units and our incentive distribution rights and 85.4% of the limited partner interests in Columbia OpCo. Given CEG’s significant ownership interest in us following this offering, we believe CEG will be motivated to promote and support the successful execution of our business strategies, including the growth of our partnership; however, we can provide no assurances that we will benefit from our relationship with CEG. While our relationship with CEG and its subsidiaries is a significant strength, it is also a source of potential conflicts. Please read “Conflicts of Interest and Fiduciary Duties.”

Columbia OpCo’s Assets and Operations

Columbia OpCo’s assets include interstate pipelines and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. Columbia OpCo’s network of interstate pipelines extends from New York to the Gulf of Mexico, serving customers in 15 northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia.

The transportation and storage rates and services of Columbia OpCo’s interstate natural gas pipeline and storage assets are subject to regulation by the FERC, which reviews and approves the tariff that establishes Columbia OpCo’s rates, cost recovery mechanisms and terms and conditions of service. The rates established under Columbia OpCo’s tariffs are a function of each jurisdictional company’s costs of providing services to customers, including a reasonable rate of return on invested capital. The FERC has jurisdiction over, among other things, the construction and operation of facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities. The FERC also has jurisdiction over the rates, terms, and conditions for the transportation and storage of natural gas in interstate commerce. All of Columbia OpCo’s interstate pipeline transportation rates and storage rates and terms of service are regulated by the FERC.

Additionally, Columbia OpCo manages mineral rights and owns and operates gathering pipelines, certain of which are regulated by the FERC, and processing facilities.

Columbia Gas Transmission

Columbia Gas Transmission owns and operates a FERC-regulated interstate natural gas transportation pipeline and storage system, which consists of approximately 11,200 miles of natural gas transmission pipeline and 89 compressor stations with 617,185 horsepower of installed capacity. Columbia Gas Transmission has a transportation capacity of approximately 10 MMDth/d, transports an average of approximately 3.7 MMDth/d, and has experienced peak day deliveries of approximately 7.9 MMDth/d. Columbia Gas Transmission serves hundreds of communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission also owns and operates one of North America’s largest underground natural gas storage systems, which includes 34 storage fields in four states with approximately 620 MMDth in total capacity, with approximately 290 MMDth of working gas capacity.

 

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Columbia Gas Transmission has historically largely operated as a means to transport gas from the Gulf Coast, via Columbia Gulf, from various pipeline interconnects, and from production areas in the Appalachia region to markets in the midwest, Atlantic, and northeast regions. As Marcellus and Utica shale gas production has grown, Columbia Gas Transmission’s operations and assets also have grown due to the increased production within the pipeline’s operating area. As the market continues to evolve, Columbia Gas Transmission is in various phases of execution and construction on a multitude of growth projects to help move the growing production of gas out of the Marcellus and Utica shale plays and into on-system markets in the northeast and mid-Atlantic markets as well as off-system markets in the Gulf Coast.

Columbia Gas Transmission plays a key role in transporting the growing supply of Marcellus and Utica gas being produced in the area. The pipeline is a highly reticulated system that operates in a variety of market areas and depends on several of its major backbone systems to transport gas throughout its service area:

 

   

R System. The R System connects the Ohio markets with Columbia Gas Transmission’s interconnect with Columbia Gulf at Leach, Kentucky.

 

   

T System. The T System connects Broad Run in West Virginia with the Pittsburgh market area in western Pennsylvania.

 

   

WB/VB System. The WB and VB System connects Broad Run in West Virginia to the Eastern market, directly into the Washington, D.C. and Baltimore markets.

 

   

KA/VA System. The KA and VA Systems connect Appalachian production in West Virginia and Kentucky to the Eastern market, directly into the Washington, D.C. and Baltimore markets.

 

   

VM System. The VM System connects the WB, VB and VA Systems with the southeastern Virginia markets, Columbia Gas Transmission’s Chesapeake LNG peaking facility, and interconnects with Transcontinental Gas Pipeline Company in southeast Virginia.

 

   

1278 System. The 1278 system connects the WB/VB System with the Philadelphia, New Jersey, and New York markets as well as with interconnects with Millennium Pipeline at the Wagoner compressor station in eastern New York.

The system is connected to approximately 1,181 natural gas receipt points and approximately 1,671 natural gas delivery points. Additionally, Columbia Gas Transmission has a highly liquid trading pool, commonly referred to as “TCO Pool,” which provides pricing transparency for significant quantities of traded supply for producers, marketers, and downstream users across the system.

 

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Customers. Columbia Gas Transmission transports natural gas for a broad mix of customers, including LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. In addition to serving markets directly connected to its system, Columbia Gas Transmission serves markets and customers in a variety of other regions through numerous interconnections with third-party interstate and intrastate pipelines.

As of December 31, 2013, Columbia Gas Transmission had 187 firm contract customers. Its three largest customers for the year ended December 31, 2013 were Columbia Gas of Ohio, Washington Gas Light Company and Columbia Gas of Pennsylvania. Contracts with these three customers accounted for approximately 20%, 12% and 7% of Columbia Gas Transmission’s contracted revenues, respectively, during 2013, although each of these customers contracted a portion of their reserved capacity to third parties that paid Columbia Gas Transmission directly for the subcontracted amounts. Columbia Gas Transmission’s three largest customers for the nine months ended September 30, 2014 were Columbia Gas of Ohio, Washington Gas Light and Columbia Gas of Pennsylvania. Contracts with these customers accounted for approximately 18%, 11% and 6% of Columbia Gas Transmission’s contracted revenues, respectively, for the nine months ended September 30, 2014. For the nine months ended September 30, 2014, Columbia Gas Transmission’s top 25 largest non-affiliated customers measured by contracted revenues generated approximately 51% of Columbia Gas Transmission’s transportation revenue.

Contracts. Under transportation agreements governed by its FERC-approved natural gas tariff, Columbia Gas Transmission offers its customers firm and interruptible transportation and storage services. For the twelve months ended December 31, 2013, approximately 98% of Columbia Gas Transmission’s transportation and storage revenues were derived from firm contracts and approximately 2% were derived from interruptible contracts. For the nine months ended September 30, 2014, approximately 98% of Columbia Gas Transmission’s transportation and storage revenues were derived from firm contracts and approximately 2% were derived from interruptible contracts.

The table below sets forth certain information regarding Columbia Gas Transmission as of September 30, 2014:

 

     Total Firm
Contracted
Capacity(1)
   Weighted
Average
Remaining Firm
Contract Life(2)

Transportation

   9.1 MMDth/d    5.9 years

Storage

   261 MMDth    4.0 years

 

(1) 

Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation or storage capacity regardless of the actual amount of transportation or storage capacity used by the customer during each month.

(2) 

Weighted by contracted capacity.

Tariff Rates. Columbia Gas Transmission’s maximum and minimum recourse rates for its transportation services are governed by its FERC-approved natural gas tariff. Terms and conditions for service under this tariff are based on firm capacity reservation charges and both firm and interruptible usage fees for transportation across its system. As of December 31, 2013, the rates in effect for 89% of Columbia Gas Transmission’s firm contracts were at the maximum recourse rates prescribed for in its tariff.

In 1996, Columbia Gas Transmission entered into a rate settlement with its customers which established new base rates under Columbia Gas Transmission’s tariff. Columbia Gas Transmission’s rate settlement with its customers, which was effective in 2013, established its modernization program and included a reduction in Columbia Gas Transmission’s base rates. Under the modernization settlement, Columbia Gas Transmission and its customers agreed to a mechanism that provides recovery and return on Columbia Gas Transmission’s initial investment of up to $1.5 billion over a five-year period, beginning in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement, Columbia Gas Transmission must annually incur at least $100 million in certain capital expenditures in order to

 

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trigger the terms of the modernization settlement’s recovery mechanism. The modernization settlement provides that, absent a FERC-approved agreement reached among Columbia Gas Transmission and its customers to extend the settlement, Columbia Gas Transmission will file a rate case to be effective no later than February 1, 2019. As part of the modernization settlement, Columbia Gas Transmission files an annual revenue sharing report. If, during the settlement, base revenue exceeds $750 million, Columbia Gas Transmission will share 75% of the revenue above $750 million with shippers. The 2013 revenue sharing report reported approximately $707 million of base system revenue.

Growth Projects. We are also pursuing the following significant expansion projects for the Columbia Gas Transmission system, which have either recently been placed in service or will be placed into service over the next several years for a total capital expenditure of approximately $330 million through September 30, 2014, with approximately $2,642 million in additional estimated costs to be paid through the end of 2018:

 

   

Warren County Project. We recently completed construction of approximately 2.5 miles of new 24-inch pipeline and modifications to existing compressor stations for a total capital cost of approximately $37 million. This project has expanded the system in order to provide up to nearly 250,000 Dth/d of transportation capacity under a long-term, firm contract. The project commenced commercial operations in April 2014.

 

   

Giles County Project. We invested approximately $25 million for the construction of approximately 12.9 miles of 8-inch pipeline, which will provide 46,000 Dth/d of firm service to a third party located off its Line KA system and into Columbia of Virginia’s system. We have secured a long-term firm contract for the full delivery volume and the project was placed in service during the fourth quarter 2014.

 

   

Line 1570 Expansion. We are replacing approximately 19 miles of existing 20-inch pipeline with a 24-inch pipeline and adding compression at an approximate cost of $18 million. The project, which was placed in service during the fourth quarter of 2014, creates nearly 99,000 Dth/d of capacity and is supported by long-term, firm contracts.

 

   

West Side Expansion. The Smithfield III Project is designed to provide a market outlet for increasing Marcellus supply originating from the Waynesburg, West Virginia and Smithfield, Pennsylvania areas on the Columbia Gas Transmission system. We invested approximately $87 million in new pipeline and compression which will provide up to 444,000 Dth/d of incremental, firm transport capacity and is supported by long-term, firm contracts. The project was placed in service during the fourth quarter of 2014.

 

   

Chesapeake LNG. The project involves the investment of approximately $33 million to replace 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives. This project is expected to be placed in service in the second quarter of 2015.

 

   

East Side Expansion. We have requested FERC authorization to construct facilities for this project, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets. Supported by long-term, firm contracts, the project will add up to 312,000 Dth/d of capacity and is expected to be placed in service by the end of the third quarter of 2015. We plan to invest up to approximately $275 million in this project.

 

   

Kentucky Power Plant Project. We expect to invest approximately $24 million to construct 2.7 miles of 16-inch greenfield pipeline and other facilities to a third-party power plant from Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service, is supported by a long-term firm contract, and will be placed in service by the end of the second quarter of 2016.

 

   

Utica Access Project. We intend to invest approximately $51 million to construct 4.7 miles of 20-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on our system. This project is expected to be in service by the end of the fourth quarter of 2016. We have secured firm contracts for the full delivery volume.

 

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Leach XPress. We finalized agreements for the installation of approximately 124 miles of 36-inch pipeline from Majorsville to Crawford CS located on the Columbia Gas Transmission system, and 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system, and approximately 101,700 horsepower across multiple sites to provide approximately 1,500,000 Dth/d of capacity out of the Marcellus and Utica shales to Leach CS located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. Virtually all of the project’s capacity has been secured with long-term firm contracts. We expect the project to go in service during the fourth quarter of 2017 and will invest approximately $1.42 billion in the Leach XPress project.

 

   

WB XPress. We expect to invest approximately $870 million in this project to expand the WB system through looping and add compression in order to transport approximately 1.3 MMDth of Marcellus Shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which include access to the Cove Point LNG terminal.

Finally, we and our customers have agreed to a mechanism that provides recovery and return on our initial investment of up to $1.5 billion over a five-year period, beginning in 2013, to modernize our system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement, we must annually incur at least $100 million in certain capital expenditures in order to trigger the terms of the modernization settlement’s recovery mechanism. During 2013, we completed more than 30 individual projects representing a total investment of approximately $300 million. The modernization program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities, and improvements in control systems.

Competition. Columbia Gas Transmission competes with a number of other interstate pipeline companies in various markets, such as Texas Eastern Transmission Company, Tennessee Gas Pipeline Company, Transcontinental Gas Pipeline Company, Dominion Transmission Inc., Equitrans, and National Fuel Gas Company. Increased competition from alternative options could have a significant financial impact on Columbia Gas Transmission; however, this risk is mitigated through the use of long-term contracts. Continued growing supply as a result of the Marcellus and Utica shale could reduce the demand for storage services.

Columbia Gas Transmission is well positioned to compete, due to its market area location and its flexible low cost services. Additionally, because its system traverses much of the Marcellus and Utica shale play, Columbia Gas Transmission has seen major producer driven demand and has been able to capitalize on that demand through developing growth projects. This has added diversification to Columbia Gas Transmission’s customer base, which historically has been dominated by large LDCs. Columbia Gas Transmission is able to receive gas from the Gulf, the Appalachian Basin (including Marcellus and Utica shale plays) and from the West. Columbia Gas Transmission also uses its extensive storage network to ensure reliable delivery of supplies.

Columbia Gulf

The Columbia Gulf pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of approximately 3,400 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Historically, the pipeline system provided direct access to Gulf of Mexico and onshore Louisiana supply sources and, through major pipeline interconnects, access to numerous natural gas producing regions, including the South Texas and Louisiana Gulf Coast, North Louisiana, East Texas, North Texas and Appalachian regions. With the rapid development of the Marcellus and Utica shale plays, traditional south-to-north gas flows are beginning to reverse and demand is increasing to transport gas in a southerly direction on Columbia Gulf’s pipelines to access various markets including LNG export facilities and markets in Florida and the Southeast via pipeline interconnects. Columbia Gulf’s pipelines include:

 

   

The Mainline System. Columbia Gulf’s Mainline System consists of three parallel pipelines that extend from southern Louisiana to a pipeline interconnection with Columbia Gas Transmission in northeastern Kentucky. The Mainline System consists of approximately 2,550 miles of pipelines with peak-design throughput capacity of 2.2 MMDth/d; and

 

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The Louisiana Laterals. The Louisiana Laterals consist of the West Lateral and the East Lateral. The West Lateral extends from an interconnection with the Mainline System along the southern tier of Louisiana westward to Cameron Parish, Louisiana, while the East Lateral extends eastward to New Orleans and Venice, Louisiana. The Louisiana Laterals consist of approximately 700 miles of pipelines with maximum peak-design capacity in excess of 1.0 MMDth/d on each lateral.

The system is connected to approximately 71 natural gas receipt points and approximately 97 natural gas delivery points.

The Columbia Gulf system offers shippers access to two actively traded market hubs—the Columbia Gulf Mainline Pool and the Columbia Gulf Onshore Pool. In addition, Columbia Gulf interconnects with the Henry Hub in South Louisiana and the Columbia Gas Transmission Pool near Leach, Kentucky. Through its approximately 22 interstate and 10 intrastate pipeline interconnections, Columbia Gulf provides upstream supply to serve growing markets in the mid-Atlantic, midwest, Florida and southeast. Columbia Gulf also has a project underway that will connect its system with the Cameron LNG export facility.

The development of the Marcellus and Utica shale plays has led to decreased demand to transport gas from the Gulf Coast to northeastern markets and we have been experiencing a corresponding decline in throughput. However, Columbia Gulf has attracted additional throughput by expanding its market and production area access through a strategy of connecting with other pipelines. For example, our new Texas Eastern interconnect in Adair, Kentucky increased our supply access by over 200,000 Dth/d. In addition, Columbia Gulf has recently reconfigured its system so that it can reverse flow on one of its three pipelines and we have secured long-term firm contracts for 100% of the delivery volume on that reversed pipeline. Flows on the other two pipelines will be reversed as part of the projects outlined below.

 

LOGO

Customers. Columbia Gulf transports natural gas for a broad mix of customers, including LDCs, municipal utilities, direct industrial users, electric power generators, marketers and producers and LNG importers and exporters. In general, LDC usage of Columbia Gulf’s pipeline system is declining and producer usage is increasing. Based on firm contracts we have entered into with these producers, we expect that by the end of 2018, a significant portion of our revenues will be generated by producers. In addition to serving markets directly connected to Columbia Gulf’s system, it serves markets and customers in a variety of other regions through numerous interconnections with third-party interstate and intrastate pipelines.

 

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As of December 31, 2013, Columbia Gulf had 70 firm contract customers. Columbia Gulf’s three largest customers for the year ended December 31, 2013 were Washington Gas Light Company, Columbia Gas of Ohio and Baltimore Gas and Electric Company. Contracts with these three customers accounted for approximately 12%, 12% and 8% of Columbia Gulf’s contracted revenues, respectively, during 2013, although each of these customers contracted a portion of their reserved capacity to third parties that paid Columbia Gulf directly for the subcontracted amounts. Columbia Gulf’s three largest customers for the nine months ended September 30, 2014 were Washington Gas Light, Columbia Gas of Ohio and Antero Resources. Contracts with these customers accounted for approximately 10%, 10% and 8% of Columbia Gulf’s contracted revenues, respectively, for the nine months ended September 30, 2014. For the nine months ended September 30, 2014, Columbia Gulf’s top 25 largest non-affiliated customers measured by contracted revenues generated approximately 67% of Columbia Gulf’s transportation.

Contracts. Under transportation agreements governed by its FERC-approved natural gas tariff, Columbia Gulf offers its customers firm and interruptible transportation services. For the twelve months ended December 31, 2013, approximately 95% of Columbia Gulf’s transportation and storage revenues were derived from firm contracts and approximately 5% were derived from interruptible contracts. For the nine months ended September 30, 2014, approximately 95% of Columbia Gulf’s revenues were derived from firm contracts and approximately 5% were derived from interruptible contracts.

The table below sets forth certain information regarding Columbia Gulf as of September 30, 2014:

 

     Total Firm
Contracted
Capacity(1)
     Weighted
Average
Remaining
Firm Contract

Life(2)
 

Transportation

     3.3 MMDth/d         3.0 years   

 

(1) 

Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation capacity regardless of the actual amount of transportation capacity used by the customer during each month.

(2) 

Weighted by contracted capacity.

Tariff Rates. Columbia Gulf’s maximum and minimum recourse rates for transportation services are governed by Columbia Gulf’s FERC-approved natural gas tariff. As of December 31, 2013, the rates in effect for 73% of Columbia Gulf’s firm contracts were at the maximum recourse rates prescribed for in our tariff.

In 2011, Columbia Gulf entered into a rate settlement with its customers, which established new base rates under Columbia Gulf’s FERC tariff. The 2011 rate settlement requires Columbia Gulf to file a cost and revenue study by May 1, 2017 but does not require Columbia Gulf to file for new rates. There are no FERC regulations that require Columbia Gulf to file a rate case. Please read “—FERC Regulation.”

Growth Projects.

 

   

West Side Expansion. Under the Gulf Bi-Direction Project we are investing approximately $113 million in system modifications and horsepower to provide a firm backhaul transportation path from the Leach, Kentucky interconnect with Columbia Gas Transmission to Gulf Coast markets on the Columbia Gulf system. This investment will increase capacity up to 540,000 Dth/d to transport Marcellus production originating in West Virginia. The project is supported by long-term firm contracts and was placed in service during the fourth quarter of 2014. The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

 

   

Rayne XPress. This project would transport approximately 1 MMDth/d of growing southwest Marcellus and Utica production away from constrained production areas to markets and liquid transaction points. Capable of receiving gas from Columbia Gas Transmission’s Leach XPress project, gas would be

 

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transported from the Leach, Kentucky interconnect with Columbia Gas Transmission in a southerly direction towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. We have secured definitive agreements for firm service for the project’s capacity and expect the project to be placed in service by the end of the fourth quarter of 2017. We expect to invest approximately $330 million on the Rayne XPress project to modify existing facilities and to add new compression.

 

   

Cameron Access Project. We are investing approximately $310 million in an 800,000 Dth/d expansion of the Columbia Gulf system through improvements to existing pipeline and compression facilities, a new state-of-the-art compressor station near Lake Arthur, Louisiana, and the installation of a new 26-mile pipeline in Cameron Parish to provide for a direct connection to the Cameron LNG Terminal. We expect the project to be placed in service by the first quarter of 2018 and have secured long-term firm contracts for approximately 90% of the increased volumes.

Competition. Historically, Columbia Gulf competed primarily with other interstate pipelines for customers seeking upstream transportation service to markets in the northeast, mid-Atlantic, midwest and southeast. Columbia Gulf’s primary competitors are Tennessee Gas Pipeline Company, Transcontinental Gas Pipeline Company, Texas Eastern Transmission Company, Texas Gas Pipeline, Natural Gas Pipeline of America, Trunkline Gas Company and ANR Pipeline Company.

With the development of the Marcellus and Utica shale plays, much of Columbia Gulf’s future transportation service will focus on moving gas supply from the Appalachian region into areas where demand is high. Columbia Gulf is in the process of capitalizing on this evolution through several projects to reverse the historic flow on the system, allowing gas to reach the Gulf Coast to serve the market demand of various processing plants and developing LNG export facilities located there. Many historic competitors, such as Transcontinental Gas Pipeline Company, have announced similar initiatives to reverse flow in order to reach the Gulf Coast. Almost all of Columbia Gulf’s southbound capacity is anticipated to be sold before project construction begins. Columbia Gulf is well positioned to compete, as it provides low cost service, including fuel, to the markets it serves. By becoming bi-directional, Columbia Gulf is addressing competitive threats by increasing the flexibility and optionality available to customers on its system. By increasing the number and diversity of supply sources and markets that it interconnects with, the Columbia Gulf pipeline system becomes a more dynamic system that presents greater value to its customers. This not only increases the potential universe of customers that have interest in Columbia Gulf’s transportation services, it also lessens the possibility that future market shifts will affect the value of Columbia Gulf’s pipeline system.

Millennium Pipeline

The Millennium Pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with approximately 43,000 horsepower of installed capacity. Millennium Pipeline has the capability to transport up to 525,400 Dth/d of natural gas to markets across New York’s Southern Tier and lower Hudson Valley, as well as to the New York City markets through its pipeline interconnections. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline and acts as operator for the pipeline in partnership with DTE Millennium Company and National Grid Millennium LLC, which each own an equal remaining share of the company.

 

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The Millennium Pipeline system is connected to 8 natural gas receipt points and 27 natural gas delivery points.

 

LOGO

Customers. Millennium Pipeline transports natural gas for a broad mix of customers, including LDCs, direct industrial users, electric power generators, and marketers and producers. In addition to serving markets directly connected to its system, Millennium Pipeline serves markets and customers through interconnections with third-party interstate pipelines.

As of December 31, 2013, Millennium Pipeline had 13 firm contract customers. Millennium Pipeline’s three largest customers for the year ended December 31, 2013 were Keyspan Gas East Corporation, Consolidated Edison Company of New York and Southwestern Energy Services Company. Contracts with these three customers accounted for approximately 29%, 26% and 13% of our contracted revenues, respectively, during 2013. Contracts with these same customers accounted for approximately 24%, 22% and 18% of Millennium Pipeline’s contracted revenues, respectively, for the nine months ended September 30, 2014. For the nine months ended September 30, 2014, Millennium Pipeline’s top 10 largest non-affiliated customers measured by contracted revenues generated approximately 71% of Millennium Pipeline’s transportation revenue.

Contracts. Under transportation agreements and FERC tariff provisions, Millennium Pipeline offers its customers firm and interruptible transportation services. For the twelve months ended December 31, 2013, approximately 99% of Millennium Pipeline’s transportation and storage revenues were derived from firm contracts and approximately 1% were derived from interruptible contracts. For the nine months ended September 30, 2014, approximately 98% of Millennium Pipeline’s transportation and storage revenues were derived from firm contracts and approximately 2% were derived from interruptible contracts.

The table below sets forth certain information regarding Millennium Pipeline as of September 30, 2014:

 

     Total Firm
Contracted
Capacity(1)
     Weighted
Average
Remaining

Firm Contract
Life(2)
 

Transportation

     1.8 MMDth/d         6.3 years   

 

(1) 

Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation capacity regardless of the actual amount of transportation capacity used by the customer during each month.

(2) 

Weighted by contracted capacity.

 

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Tariff Rates. Millennium Pipeline’s maximum and minimum recourse rates for transportation services are governed by Millennium Pipeline’s FERC-approved natural gas tariff. Terms and conditions for service under this tariff are based on firm capacity reservation charges and both firm and interruptible usage fees for transportation across different zones. As of December 31, 2013, 91% of the rates in effect for Millennium Pipeline’s firm contracts were less than the maximum recourse rates prescribed for in our tariff.

In 2006, the FERC issued an order in a proceeding under Section 7 of the NGA accepting the base rates to be charged under Millennium Pipeline’s FERC tariff. In compliance with the order, Millennium Pipeline filed a cost and revenue study in 2011, which was accepted for filing by the FERC in January 2012. Neither the FERC order nor FERC regulations require Millennium Pipeline to file for new base rates, thereby providing rate certainty, subject to further negotiation, the filing of a rate case, or a customer filing a complaint.

Growth Projects.

 

   

Hancock Compressor Project. Millennium Pipeline has invested approximately $40 million to increase firm transportation capacity to its interconnection with a downstream pipeline at Ramapo, New York by 107,500 Dth/d and provide the flexibility to meet an anticipated need for 115,000 Dth/d of firm transportation capacity between an interconnect with the Laser Northeast Gathering System and Columbia Gas Transmission. The project was placed in service in the first quarter of 2014.

 

   

Minisink Compressor Project. Millennium Pipeline has invested approximately $50 million to add compression in Orange County, NY that will effectively increase deliverability at Ramapo to 675,000 Dth/d. This project added two 6,130 horsepower natural gas turbine-driven centrifugal compressors to increase pressure and was placed in service in the second quarter of 2013.

Competition. Millennium Pipeline was recently constructed to fulfill largely unmet demand and two of its partners are significant customers; as such, Millennium Pipeline has limited direct competition.

Hardy Storage

The Hardy Storage facility is a FERC-regulated interstate natural gas storage system, which consists of 29 storage wells in a depleted gas production field in Hampshire and Hardy counties, West Virginia, 36.7 miles of pipeline and 7,100 horsepower of installed capacity. The facility interconnects with Columbia Gas Transmission and has approximately 12 MMDth of working gas capacity and 176,000 Dth/d of withdrawal capacity. Columbia Gas Transmission owns a 49% interest in Hardy Storage and acts as operator for the system. Columbia Hardy Corporation, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% interest, respectively, in Hardy Storage.

Customers. As of December 31, 2013, Hardy Storage had three firm contract customers. These customers were Washington Gas Light Company, Piedmont Natural Gas Company, Inc. and Baltimore Gas and Electric Company. Contracts with these three customers accounted for approximately 47%, 40% and 13% of contracted revenues, respectively, during 2013. Contracts with these same customers accounted for approximately 47%, 40% and 13% of Hardy Storage’s contracted revenues, respectively, for the nine months ended September 30, 2014.

Contracts. Hardy Storage’s capacity is 100% contracted and its contracts with its customers will expire on March 31, 2023.

Tariff Rates. Hardy Storage’s assets and operations are regulated by the FERC under the NGA.

In 2013, Hardy Storage entered into a rate settlement with its customers which established new base rates under Hardy Storage’s FERC tariff. On or before May 1, 2019, Hardy Storage is required to file a cost and revenue study with the FERC. The rate settlement does not require Hardy Storage to file for new base rates, thereby providing rate certainty, subject to further negotiation, the filing of a rate case, or a customer filing a complaint. There are no FERC regulations that require Hardy Storage to file a rate case. Please read “—FERC Regulation.”

 

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Columbia Midstream

Columbia Midstream is a non-FERC regulated business that provides midstream services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 104 miles of gathering pipeline and one compressor station with 6,800 horsepower of installed capacity, as well as a 50% ownership interest in Pennant Midstream LLC, which owns wet gas gathering pipeline facilities, a cryogenic processing plant and an NGL pipeline. Columbia Midstream supports the growing production in the Utica and Marcellus shale plays.

Revenues associated with our gathering systems represented 100% of our total revenues for the year ended December 31, 2013 and the nine months ended September 30, 2014, respectively. Our gathering system is composed of pipelines ranging in diameter from 16 inches to 24 inches. Columbia Midstream currently gathers natural gas from approximately five receipt points with delivery into three interstate pipelines.

Average throughput on our gathering systems for the year ended December 31, 2013 and the nine months ended September 30, 2014 was 298 MDth/d and 327 MDth/d, respectively.

Majorsville Gathering System. The 46-mile Majorsville gathering system is a wet gas gathering pipeline system, located in the Majorsville, West Virginia vicinity and gathers Marcellus shale production for downstream transmission. We have invested approximately $83 million in the system in three projects for the Majorsville gathering system. Substantially contracted with long-term firm service agreements, the pipeline and compression assets allow us to gather and deliver more than 350,000 Dth/d of Marcellus production gas to the Majorsville MarkWest Liberty processing plants operated by MarkWest Liberty Midstream & Resources LLC. Two of the three projects, which were placed into service in August 2010, created an integrated gathering system serving Marcellus production in southwestern Pennsylvania and northern West Virginia. The projects consisted of the construction of a 22-mile 16-inch low pressure gathering line and a 17-mile 20-inch high pressure gathering line. The third project, which was placed into service in April 2011, involved construction on a 7-mile 16-inch and 20-inch pipeline. The pipelines deliver residue gas from the Majorsville MarkWest Liberty processing plant to the Texas Eastern Wind Ridge compressor station in southwestern Pennsylvania, providing significant additional capacity to Northeastern markets. Long-term firm service agreements are in place with anchor shippers for 100% of capacity. In 2013, the compressor station was updated with four new compressors with a total of 6,800 horsepower.

 

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Big Pine Gathering System. The Big Pine gathering system consists of 58 miles of pipeline facilities in the hydrocarbon-rich Western Pennsylvania shale production region, including a 45-mile 20-inch pipeline and a 13-mile 24-inch pipeline. We have invested approximately $165 million in the system for right-of-way acquisitions and installation, refurbishment and operation of the pipeline facilities. The newly constructed pipeline system, which was placed in service in April 2013, has an initial combined capacity of 425 MMcf/d. Natural gas production is delivered to Columbia Gas Transmission and two other third-party pipelines in Pennsylvania. There are currently two meters where gas is delivered into Big Pine. Big Pine is currently fully contracted.

 

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Customers. Our gathering systems have approximately five receipt points with a number of natural gas producers, including Range Resources, Chesapeake Energy and XTO Energy Inc. The largest producer of natural gas delivered to the gathering systems is Chesapeake Energy, which represented 38% of the 298 MDth/d of natural gas supplied to our gathering systems for the year ended December 31, 2013.

Contracts. Our gathering systems are primarily supported by long-term, fee-based gas gathering agreements, with terms ranging from 10 to 15 years typically with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. The rates for gathering services are primarily based on the expected capital expenditures and available capacity.

Growth Projects.

 

   

Washington County Gathering. A large producer has contracted with us to build a 21-mile dry gas gathering system consisting of 8-inch, 12-inch, and 16-inch pipelines, as well as compression, measurement and dehydration facilities. We expect to invest approximately $120 million beginning in 2014 through 2018 and expect to commence construction in early 2015. The initial wells are expected to come on-line in the fourth quarter of 2015. The project is supported with minimum volume commitments and further enhances Columbia Midstream’s relationship with a producer that has a large Marcellus acreage position.

 

   

Big Pine Expansion. We are investing approximately $65 million to make a connection to the Big Pine pipeline and add compression facilities that will add incremental capacity. The additional 9-mile 20-inch pipeline and compression facilities will support Marcellus shale production in western Pennsylvania. We expect 50% of the increased capacity generated by the project to be supported by a long-term fee-

 

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based agreement with a regional producer, with the remaining capacity expected to be sold to other area producers in the near term. We expect the project to be placed in service by the third quarter of 2015.

Competition. Competition for natural gas gathering is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location of gathering systems, reputation and fuel efficiencies. Our principal competitors for low and high pressure gathering systems include numerous independent gas gatherers and integrated energy companies, who have plans to build gathering facilities to move volumes to interstate pipelines. Some of our competitors have capital resources and control supplies of natural gas greater than we do.

We believe that our customer focus, demonstrated by our ability to offer a broad range of services, strategic location of our systems, and our flexibility in considering various types of contractual arrangements, allows us to compete effectively. The strategic location of our assets and the long-term nature of our contracts also provide a significant competitive advantage.

Pennant Joint Venture

Columbia OpCo indirectly owns a 50% ownership interest in Pennant, a joint venture with an affiliate of Hilcorp, which owns 43 miles of a wet gas gathering pipeline, a gas processing plant and a NGL pipeline. The system is referred to as the Hickory Bend gathering system.

Pennant constructed the system, which includes 20-24 inch wet gas gathering pipeline facilities with a capacity of approximately 500 MMcf/d, a gas processing facility in New Middletown, Ohio that has an initial capacity of 200 MMcf/d and an NGL pipeline with an initial capacity of 45,000 Bbl/d that can be expanded to 90,000 Bbl/d. Consistent with the terms of the joint venture, Columbia Midstream operates the gas processing facility, NGL pipeline and associated wet gas gathering system. The joint venture is designed and anticipated to serve other producers with significant acreage development in the area with an interest in obtaining capacity on the system. The construction of the facilities allows Pennant to become a full-service midstream solution for producers in the northern Utica shale region, offering access to wet gas gathering and processing as well as residue gas and NGL takeaway to attractive market destinations. Our investment in this venture, including the gathering pipeline, related laterals, NGL pipeline and the processing plant, is approximately $193 million. A portion of the facilities were placed in service in the fourth quarter of 2013 and in the second and third quarter of 2014, and the remainder were placed in service in the fourth quarter of 2014.

 

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Customers. The Pennant gathering system will have four initial receipt points for Hilcorp production. There are several other producers in the Pennant footprint that have significant acreage positions that can be effectively served by the Pennant gathering and processing facilities.

Contracts. The primary term of the anchor gathering and processing agreements, which started in July 2014, are 10 years with multi-year roll over provisions. Once ramp up volumes are achieved, minimum volume commitments will account for approximately 37% and 68% of the initial Pennant gathering and processing capacity, respectively. The rates for gathering and processing service are based on expected capital expenditures and a required rate of return.

Growth Projects. Pennant expects to add additional plant capacity in the next two to five years to support the growing drilling activity in the area. Pennant also intends to construct measurement stations and make connections to the main gathering line to deliver the field gas that will be drilled.

Competition. Competition for natural gas gathering is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location of gathering systems and processing plants, reputation and fuel efficiencies. Competitive factors affecting our processing service also includes availability of capacity, proximity to supply and industry marketing centers and cost efficiency and reliability of service. Our principal competitors for low and high pressure gathering systems and gas processing include numerous independent gas gatherers and integrated energy companies, who have plans to build gathering facilities or gas processing plants. Some of our competitors have capital resources and control supplies of natural gas greater than we do.

We believe that our customer focus, demonstrated by our ability to offer a broad range of services, strategic location of our systems, and our flexibility in considering various types of contractual arrangements, allows us to compete effectively. In our Utica footprint, our early entrance through our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of these resource plays. The strategic location of our assets and the long-term nature of our contracts also provide a significant competitive advantage.

Columbia Energy Ventures, LLC

Columbia OpCo owns 100% of the ownership interests in CEVCO, which is a non-FERC regulated business that manages our mineral rights positions in the Marcellus and Utica shale areas including the production rights to over 450,000 acres. CEVCO has sub-leased the production rights in four storage fields in Ohio, West Virginia and Pennsylvania, and also has contributed its production rights in another storage field.

Customers. CEVCO has subleased the production rights below the four storage fields to five producers, with production taking place on three of those fields. CEVCO has also contributed its production rights to another storage field to Hilcorp, and participates as a working interest partner in the development of a broader acreage dedication. CEVCO has, and will continue to pursue opportunities to leverage its mineral rights positions into broader gathering and processing projects for Columbia Midstream.

Contracts. Each sublease is negotiated separately and terms vary depending on each unique storage field and the expectations of the sublessee. CEVCO receives an overriding royalty from the producers for successful drilling efforts on the subleased acres. Some of the sublease agreements also allow CEVCO the option to participate in the subleased acres as a working interest owner. CEVCO is currently participating as a working interest owner in one of its subleases. The agreement with Hilcorp gives CEVCO the option to participate in a specified acreage area in the Utica/Point Pleasant formation, with CEVCO having both a working interest and overriding royalty interest in the well production.

 

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Growth Projects. We have invested approximately $28 million in the Cardinal Upstream project, in which we are a 5% working interest owner with Hilcorp in the development of wells. In addition, we have received an overriding royalty interest of 0.7% on all drilling activity in the area of mutual interest. Currently, approximately 29 wells are producing with approximately 50 wells scheduled to be drilled and completed in the next 18 months. Beginning in 2015, we expect to make an annual contribution of approximately $22 million to the project.

CNS Microwave

CNS Microwave is an exempt telecommunications company and subsidiary of Columbia OpCo. With assets in Pennsylvania, Maryland, Virginia, West Virginia, Ohio, Kentucky, Tennessee, Mississippi and Louisiana, CNS Microwave provides ancillary communication services to us and third parties.

FERC Regulation

General. Our interstate natural gas transportation and storage system operations are regulated by the FERC under the NGA and the NGPA, and the FERC’s regulations under those statutes. Generally, the FERC’s authority extends to:

 

   

interstate transportation and storage of natural gas;

 

   

rates, charges, and operating terms and conditions for natural gas transportation and storage services;

 

   

the types of services we may offer our customers;

 

   

certification and construction of new facilities;

 

   

initiation, acquisition, extension or abandonment of services or facilities;

 

   

maintenance of accounts and records;

 

   

affiliate interactions;

 

   

depreciation and amortization policies; and

 

   

the initiation and discontinuation of services.

Our interstate pipeline companies hold certificates of public convenience and necessity issued by the FERC pursuant to Section 7 of the NGA permitting the construction, ownership, and operation of their respective interstate natural gas pipeline and storage facilities and the provision of related activities and services. These certificate authorizations require our interstate pipeline companies to provide on a non-discriminatory basis open-access services to all customers who qualify under their respective FERC-approved tariff.

The FERC regulates the rates and charges for transportation and storage in interstate commerce. Interstate pipeline companies may only charge rates that they have been authorized to charge by the FERC. In addition, interstate pipeline companies may only charge rates that have been found to be just and reasonable. The NGA prohibits interstate pipeline companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum and minimum recourse rates that may be charged by our interstate pipeline companies for transportation and storage services are established through the FERC’s ratemaking process. The maximum filed recourse rates for these services are based on the cost of service including recovery of and a return on the company’s actual prudent historical cost investment. In addition, the FERC’s policy permits our interstate pipeline companies to include an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if we prove that the ultimate owners of our partnership interests have an actual or potential income tax liability on such income. The maximum applicable recourse rates and terms and conditions for service are set forth in each natural gas company’s FERC-approved tariff.

 

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Pursuant to the FERC’s jurisdiction over rates, proposed rate increases may be challenged by protest and existing rates may be challenged by complaint or sua sponte by the FERC. Any successful challenge to our existing or proposed rates, or changes in FERC’s ratemaking policies, could have an adverse impact on our revenues associated with providing transportation and storage services. The most recent rate cases establishing the maximum recourse rates that each of our interstate pipeline companies are allowed to charge are described above in “—Columbia OpCo’s Assets and Operations.”

Most interstate pipeline companies are authorized to offer discounts from their FERC-approved maximum recourse rates when competition warrants such discounts. Interstate pipeline companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer the recourse rate to a prospective shipper as an alternative to the negotiated rate. Interstate pipeline companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory.

Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) amended the NGA, to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and provided the FERC with additional civil penalty authority. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of EPAct 2005. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, FERC rules, regulations and orders, or the terms of our tariffs on file with the FERC, up to $1,000,000 per day per violation.

Failure to comply with the NGA, the NGPA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

Proposed Rulemaking on Gas-Electric Coordination. On March 20, 2014, the FERC issued a notice proposing revisions to its natural gas regulations that it states are designed to better coordinate the scheduling for natural gas and electricity markets. The FERC states that the revisions are intended to address impacts on reliable and efficient operation of both industries that have resulted from the increased reliance on natural gas by electric generation, and to provide increased flexibility for natural gas customers. The proposed rules would change the start of the natural gas operating day and increase the number of intraday nomination cycles to four. The scheduling changes would impose additional systems and administrative costs on our interstate pipeline companies.

Regulation of Gathering Pipelines. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to

 

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the gatherer for handling. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Complaint-based regulation generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Seasonality

Natural gas demand for heating is impacted by weather, which in turn influences the value of transportation and storage. Peak demand for natural gas typically occurs during the winter months, however, because a high percentage of our revenues are derived from firm capacity reservation fees under long-term contracts, our transportation and storage revenues are not generally seasonal in nature. Net revenues for 2013 were approximately 26% in the first quarter, 23% in the second quarter, 24% in the third quarter, and 27% in the fourth quarter.

Environmental and Occupational Health and Safety Regulation

General. Our activities are subject to stringent and complex federal, state, and local laws and regulations governing worker safety and health as well as environmental protection, including air emissions, water quality, wastewater discharges, solid waste management, and natural resource, ecosystem and species protection and management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, plans, and other approvals. These laws and regulations also can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of our wastes; requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators; limiting or prohibiting construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; imposing specific health and safety criteria addressing worker protection; and preventing continued operation of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. For example, on August 29, 2014, Pike County Conservation District issued a notice of violation to Columbia Transmission alleging violations of the Pennsylvania Clean Streams Law and Columbia Transmission’s Erosion and Sediment Control General Permit in connection with Columbia Transmission’s Line 1278 Replacement Project and seeking payment of a penalty. Discussions are ongoing with the Pike County Conservation District to resolve this notice of violation. We expect any such payment associated with final settlement of this matter to be insignificant to our financial results.

We accrue for expenses associated with environmental liabilities when the costs are probable and reasonably estimable. The amount of any accrual for environmental liabilities could change substantially in the future due to factors including the nature and extent of any contamination that we may be required to remediate, changes in remedial, material handling, or permitting requirements, technological changes, discovery of new information, and the involvement and direction taken by the EPA, FERC, DOT and any other governmental authorities on these matters.

 

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We believe that compliance with existing federal, state and local environmental laws and regulations are not likely to have a material adverse effect on our business, financial position, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental and worker health and safety laws and regulations, as amended from time to time, that are applicable to our natural gas transportation activities.

Waste Management. Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), Toxic Substance Control Act, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous wastes, which, pursuant to a regulatory exemption, currently includes certain wastes associated with the exploration and production of oil and natural gas.

Site Remediation. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for the disposal of hazardous substances at offsite locations, such as landfills. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. If we are considered a responsible party under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or wastes into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own or lease properties that for many years have been used for the transportation and compression of natural gas. Although we typically have used operating and disposal practices that were standard in the industry at the time, wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

Columbia Gas Transmission continues to conduct work at specific sites subject to a 1995 AOC with the EPA. The AOC requires Columbia Gas Transmission to investigate and remediate historic waste management areas. The cost of future remediation has been estimated based upon the information available, applicable remediation standards and experience at similar facilities. The actual future expenditures depend on many factors, including the nature and extent of contamination, and the method of cleanup.

 

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Air Emissions. The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

We may incur significant expenditures in the future for air pollution control equipment in connection with revised or changing regulatory requirements and in obtaining or maintaining operating permits and approvals for air emissions. For instance, in 2012, the EPA published final rules that subject oil and natural gas transmission and storage operations, among others, to regulation under the New Source Performance Standards and National Emission Standards of Hazardous Air Pollutants federal programs and impose, among other things, more stringent standards for monitoring and repairing volatile organic compound emissions from equipment leaks as well as added monitoring requirements of other equipment and processes. In addition, we may be required to supplement or modify our air emission control equipment and strategies due to changes in EPA’s national ambient air quality standards for ozone and fine particulates, changes in state implementation plans for controlling air emissions in areas that have not achieved EPA’s air quality standards, or stricter regulatory requirements for sources of hazardous air pollutants. In addition, in April 2014, the Pennsylvania Department of Environmental Protection proposed a rule, Additional RACT Requirements for Major Sources of NOx and VOCs, which may require emissions reductions from several of Columbia Gas Transmission’s turbines and reciprocating engines. The rule is expected to be finalized by the end of 2015. We are required to monitor our facilities for emissions and leaks of certain gases commonly referred to as GHGs, including carbon dioxide and methane, and new requirements for addressing GHGs from our pipelines may apply in the future. Compliance with existing air emissions requirements may cause us to incur potentially significant costs with respect to our operations; however, we do not believe that compliance with any such future requirements will have a material adverse effect on our operations.

Scientific studies have suggested that emissions of GHGs may be contributing to warming of the Earth’s atmosphere. In December 2009, the EPA made findings that emissions of GHGs present an endangerment to public health and the environment and subsequently has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews regarding GHGs for certain large stationary sources that are already potential major sources of conventional pollutant emissions, regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities in the U.S. on an annual basis. Only recently, on March 28, 2014, President Obama announced his methane emissions initiative that will focus on methane emissions reduction from specified sources including, among others, the oil and natural gas business sector. While we participate in the Natural Gas Star program, a voluntary program to identify leaks from natural gas pipelines and emissions from compressor stations and other combustion sources along the pipeline, and identify and encourage reduction of those leaks and emissions, the EPA may propose emission standards or performance standards at some future time to further address GHGs from pipelines. Additionally, while the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, in the absence of any significant activity by Congress in recent years to adopt such legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Also, there exists the possibility that states and the U.S. Congress may in the future legislate to reduce emissions of GHGs, which legislation may include a carbon tax on GHG emissions. Natural gas has a lower GHG emission rate than other fossil fuels when combusted; however, it has a high GHG emission rate when released without combustion. Therefore, regulatory or legislative actions can have a mixed impact on natural gas. We are monitoring and reporting GHG emissions from our operations pursuant to the EPA’s GHG emissions reporting rule and further believe that our programs mitigate the risk from GHG regulation by minimizing leaks of uncombusted natural gas. The adoption of any legislation or regulations that imposes a carbon tax, requires reporting of GHGs or otherwise restricts emissions

 

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of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for our transportation services. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our operations.

Water Discharges. The Federal Water Pollution Control Act (“CWA”) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. and covered state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Spill prevention, control and countermeasure requirements under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a tank spill or leak. The CWA also regulates storm water runoff from certain industrial and construction facilities. Accordingly, some projects of the company may be required to obtain and maintain storm water discharge permits, comply with mitigation measures, and monitor and sample storm water runoff from their facilities. Additionally, certain construction activities that impact streams or wetlands are required to obtain and follow disturbance and fill permits. Under the CWA, federal and state regulatory agencies may impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. In the event that any releases from our pipelines were to threaten drinking water systems, we would have to take actions to mitigate any damage to drinking water supplies.

The federal Oil Pollution Act of 1990 (“OPA”), which amends and augments the CWA, establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills, mitigation of spills, and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to an oil spill.

Environmental Impact Assessments and Plans. Significant federal decisions, such as issuance of a Certificate of Public Convenience and Necessity or permit authorizing construction of a new interstate gas transmission pipeline or authorizing natural gas transportation activities to be conducted on federal lands, are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the FERC, to evaluate major agency actions having the potential to impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment or an Environmental Impact Statement, dependent upon the potential impacts, that assess the potential direct, indirect and cumulative impacts of a proposed project. Environmental Assessments and Environmental Impact Statements are made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA, which process has the potential to delay, limit scope, or increase the cost of, any construction projects that we may pursue.

Endangered Species Act Considerations. Our pipeline maintenance or construction activities may adversely affect wildlife, migratory birds, or a natural ecosystem that supports a protected animal or plant. We are required by various laws, including the federal Endangered Species Act (“ESA”) and comparable state laws to identify potential impact through species surveys and to take actions to mitigate possible impacts. In some cases, we may be required to submit plans for approval to protect such species. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. We have developed a Habitat Conservation Plan and received an Incidental Take Permit from the United States Fish and Wildlife Service for a one-mile corridor around our current footprint, excluding midstream assets. This will satisfy most of the current requirements of the ESA and provides protection in the event of take of an endangered species. In areas where we plan to conduct expansion activities,

 

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the ESA could cause us to incur increased costs arising from species protection measures and could result in delays or limitations in the scope development of such projects; however, we do not believe that compliance with any ESA requirements will have a material adverse effect on our operations.

Employee Health and Safety. We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Some of our facilities are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security (“DHS”), to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS adopted Risk Based Facility Tiering and some of our facilities are subject to enhanced security requirements.

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions, but the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it may seek to further expand its regulation of hydraulic fracturing. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. While we do not conduct horizontal hydraulic fracturing, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our natural gas exploration and production customers’ operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could adversely affect our natural gas transmission and storage services as well as our midstream business expansion opportunities. Further, several federal governmental agencies have conducted or are conducting reviews and studies on the environmental aspects of hydraulic fracturing activities, including the White House Council on Environmental Quality, the EPA, the federal Bureau of Land Management, and the U.S. Department of Energy. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

Pipeline Safety and Maintenance

Our natural gas pipeline operations are subject to regulation by the PHMSA of the U.S. Department of Transportation (“DOT”) under the NGPSA. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities. Pursuant to the authority granted under the NGPSA, PHMSA has promulgated regulations governing pipeline design, installation, testing, maximum

 

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operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures.

The NGPSA has been amended from time to time, including by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The PSI Act established mandatory inspections for all U.S. natural gas transportation pipelines, and some gathering lines in high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas. The PIPES Act required mandatory inspections for certain natural gas transmission pipelines in HCAs and required that rulemaking be issued for, among other things, pipeline control room management. Pursuant to the authority granted under the NGPSA, as amended, PHMSA has established a series of rules requiring pipeline operators such as us to develop and implement integrity management programs for natural gas transmission pipelines in HCAs that require the performance of frequent inspections and other precautionary measures. PHMSA may assess penalties for violations of these and other requirements imposed by its regulations. We have met the regulatory deadline to perform a baseline assessment of all originally identified HCAs by December 17, 2012. In addition, since 2007, we have performed initial assessments on over 3,690 miles of pipeline mainly using in-line inspection methods. This includes approximately 300 miles of high consequence areas. In addition, beginning in 2010, we began reassessment on many pipeline segments initially inspected under the program. Total costs of the program between 2009 and 2013 were approximately $181 million ($96 million in capital costs and $85 million in expenses). Regulations require that new high consequence areas be identified annually. New HCA’s identified are required to be assessed within ten years. We currently estimate an annual average cost of approximately $50 million for years 2014 through 2016 to perform necessary integrity management program testing on our pipelines required by existing PHMSA regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, for which costs could be substantial. However, we do not expect that any such costs would be material to our financial condition or results of operations.

Most recently, the NGPSA was amended on January 3, 2012, when President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which reauthorized funding for federal pipeline safety programs through 2015 and required increased safety measures for natural gas transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines that operate above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. In addition, PHMSA has recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have reviewed all of our MAOP records in populated areas in compliance with the advisory bulletin. In addition, we are in the process of completing MAOP records validation on the rest of our pipeline system. We continue to research areas where records could not be found and/or areas where records may not support the current MAOP of the pipeline.

We believe that our natural gas pipeline operations are in substantial compliance with currently applicable PHMSA requirements. Nonetheless, the safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any future implementation of PHMSA rules or any future issuance or reinterpretation of PHMSA guidance with respect to safety involving natural gas pipelines could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our operational results or financial position. For example, in

 

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August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency was seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. In addition, PHMSA is currently in the process of drafting regulations on an integrity verification process for certain pipeline installed before the pipeline safety regulations were enacted as well as for other pipe with legacy issues. Under this process certain pipelines may require testing, retesting, or replacement to meet the standards. These rules are still in the process of being drafted and PHMSA continues to evaluate the public comments received with respect to more stringent integrity management. We continue to monitor regulatory developments associated with the pending regulations to help anticipate future operational and financial risks associated with such requirements.

While states are largely preempted by federal law from regulating pipeline safety, states may assume responsibility for enforcement of federal intrastate pipeline safety regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with state laws and regulations applicable to our operations. We inspect our pipelines regularly in compliance with federal and state maintenance requirements and have implemented inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements. For example, we maintain a corrosion control program to protect the integrity of the pipeline and prolong its life. The corrosion control program includes the installation and operation of groundbeds and rectifiers along the pipeline system to maintain adequate cathodic protection, as required by PHMSA. We determine the adequacy of this program through bi-monthly monitoring of the output of these systems, annual checks of cathodic protection readings at various points along the pipeline and at compressor stations as well as by performing close interval potential surveys. We also monitor the pipeline internally both by sampling liquids or solids that we remove from the pipeline and by performing an internal inspection whenever the interior of the pipeline is exposed. We inspect the external coating condition of the pipeline every time we excavate and expose the pipeline. In addition, many of our pipelines are inspected through the use of in-line inspection tools. Such tools can detect metal loss and other anomalies on the pipeline. Significant anomalies are investigated and repaired. The application of these monitoring and inspection techniques assist us in controlling and reducing metal loss and limiting corrosion, which we believe will extend the service life of the pipeline.

In December 11, 2012, a natural gas pipeline incident involving an ignition and fire occurred in northern Kanawha County, WV, along a 20-inch diameter Columbia Gas Transmission LLC Line SM-80. The incident resulted in damage to several residences; however, there were no fatalities or serious injuries. On December 20, 2012, PHMSA issued a compliance order for the incident. We fulfilled all of the requirements of the order, and on April 2, 2014, PHMSA issued a letter closing the order and stating that no further action was contemplated. An investigation of the incident was performed by the National Transportation Safety Board (“NTSB”). NTSB issued a final accident report concerning the incident on March 10, 2014. The report contained three process recommendations to Columbia Gas Transmission and one recommendation to PHMSA. Columbia Gas Transmission is in the process of implementing measures to comply with those recommendations. There is one pending potential civil case relative to the incident.

A pipeline rupture and fire occurred on February 13, 2014 on a 30-inch diameter Columbia Gulf pipeline, Line 200, in Adair County, Kentucky. The incident resulted in the loss of several houses and associated damages, however, there were no fatalities or serious injuries. PHMSA issued a compliance order for the incident on February 14, 2014. The order requires the reduction of operating pressure along a 250 mile segment of the pipeline and other actions to determine the cause of the event and determine if similar conditions exist elsewhere on the pipeline. We are working closely with PHMSA to determine and carry out a comprehensive integrity verification and remediation plan to ensure the integrity of the pipeline. It is anticipated that these actions will be carried out over the next two to three months. Civil damage claims resulting from the incident remain pending.

 

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A pipeline rupture occurred on Columbia Gulf Line 100 on December 14, 2007. The incident resulted in one fatality. We performed a comprehensive assessment and corrective measures on our mainline pipelines in the Columbia Gulf pipeline system following the event. There are no known outstanding regulatory issues associated with this event.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to easements or surface leases between us, as lessee, and the fee owner of the lands, as lessors. We, our predecessor or our respective affiliates, have leased these lands, in some cases, for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, permit or license held by us or to our title to any material lease, easement, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, permits and licenses.

Insurance

Our insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.

Facilities

We lease our offices in Houston, Texas under a lease agreement, which expires on June 30, 2021. Other office space is shared with NiSource affiliates and we are charged an allocation for the use of space by our employees.

Employees

Neither we nor Columbia OpCo has any employees. As of September 30, 2014, NiSource had 8,830 employees, of which 1,460 were involved in the business of our predecessor. Of these 1,460 employees, 254 are covered by collective bargaining agreements that expire in 2016 and 2017. There have been no strikes or lockouts, and NiSource has not experienced any work stoppages throughout its history. We believe that NiSource’s relationship with the local union officials and bargaining committees is open and positive.

Legal Proceedings

In the ordinary conduct of our business, we, Columbia OpCo and CEG are subject to periodic lawsuits, investigations and claims, including, environmental claims and employee related matters. See “—Environmental and Occupational Health and Safety Regulation.” Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we or CEG are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.

 

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MANAGEMENT

Management of Columbia Pipeline Partners LP

We are managed and operated by the board of directors and executive officers of our general partner, CPP GP LLC, a wholly owned subsidiary of our sponsor. As a result of owning our general partner, our sponsor will have the right to appoint all of the members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the NYSE. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have six directors, at least one of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering. Our sponsor will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of our sponsor. The amount of time that our executive officers will devote to our business and the business of our sponsor will vary in any given year based on a variety of factors. We expect that our executive officers will devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. However, our executive officers’ fiduciary duties to our sponsor and other obligations may prevent them from devoting sufficient time to our business and affairs.

Following the completion of this offering, neither our general partner nor our sponsor will receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner and its affiliates, including our sponsor, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Please read “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

In evaluating director candidates, our sponsor will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner upon the completion of this offering. Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board. There are no

 

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family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of our sponsor.

 

Name

   Age     

Position With Our General Partner

Robert C. Skaggs, Jr.

     60       Director Nominee and Chief Executive Officer

Glen L. Kettering

     60       Director Nominee and President

Stephen P. Smith

     53       Director, Chief Financial Officer and Chief Accounting Officer

Robert E. Smith

     45       Director Nominee, General Counsel and Corporate Secretary

Stanley G. Chapman, III

     49       Director Nominee and Chief Commercial Officer

Thomas W. Hofmann

     62       Director Nominee

Robert C. Skaggs, Jr. Mr. Skaggs will be appointed to our board of directors immediately prior to the date our common units are listed for trading on the NYSE. Mr. Skaggs currently serves as our Chief Executive Officer, a position he has held since December 2014. Additionally, Mr. Skaggs serves as President and Chief Executive Officer of NiSource, positions he has held since October 2004 and July 2005, respectively. He also is a past chairman and current director of the American Gas Association’s board of directors, and has served on the board of directors of the Southeastern Gas Association. He is a member of the Midwest Energy Association, the American Bar Association, the Energy Bar Association and the West Virginia Bar Association. He also is a trustee of the NiSource Charitable Foundation, and has served in leadership roles for a variety of charitable, community and civic efforts. Mr. Skaggs earned a Bachelor of Arts degree in Economics from Davidson College, a Juris Doctor degree from West Virginia University College of Law and a Master of Business Administration degree from Tulane University. Mr. Skaggs’s extensive energy industry background, leadership experience developed while serving in several executive positions and strategic planning and oversight brings important experience and skill to our board of directors. Mr. Skaggs is expected to serve as Chairman and Chief Executive Officer of HoldCo effective at the time of the spin-off.

Glen L. Kettering. Mr. Kettering will be appointed to our board of directors immediately prior to the date our common units are listed for trading on the NYSE. Mr. Kettering currently serves as our President, a position he has held since December 2014. Additionally, Mr. Kettering serves as Executive Vice President and Group Chief Executive Officer for NiSource’s Columbia Pipeline Group business unit, positions he has held since April 2014. Prior to April 2014, Mr. Kettering served as Senior Vice President, Corporate Affairs, where he was responsible for leading NiSource’s investor relations, communications and federal government affairs functions. He joined the law department of Columbia Gas Transmission in 1979 and has served in a variety of legal, regulatory, commercial and executive roles, including President of Columbia Gas Transmission and Columbia Gulf. Mr. Kettering earned a Bachelor of Arts degree in Business Administration from West Virginia University and a Juris Doctor degree from the West Virginia University College of Law. Mr. Kettering’s extensive energy industry background, leadership experience developed while serving in several executive positions and strategic planning and oversight brings important experience and skill to our board of directors. Mr. Kettering is expected to serve as President of HoldCo effective at the time of the spin-off.

Stephen P. Smith. Mr. Smith currently serves as our interim sole director, a position he has held since September 2014, and also serves as our Chief Financial Officer and Chief Accounting Officer, positions he has held since December 2014. Additionally, Mr. Smith has been Executive Vice President and Chief Financial Officer of NiSource, an affiliate of ours, since 2008. Mr. Smith currently serves as a director of GP Natural Resource Partners LLC, a position he has held since 2004. Mr. Smith earned a Master of Business Administration degree from the University of Chicago Graduate School of Business and a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Mr. Smith was selected to serve as a director because of his management expertise and his extensive financial background. Mr. Smith is expected to serve as Executive Vice President and Chief Financial Officer of HoldCo effective at the time of the spin-off.

 

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Robert E. Smith. Mr. Smith will be appointed to our board of directors immediately prior to the date our common units are listed for trading on the NYSE. Mr. Smith currently serves as our General Counsel, a position he has held since December 2014. Mr. Smith also serves as Corporate Secretary, Vice President and Deputy General Counsel of NiSource, positions he has held since September 2008 and April 2013, respectively. Mr. Smith serves as chair of the board of directors of Global Action and was on the national board of the Society of Corporate Secretaries and Governance Professions, where he was both chair of its Policy Advisory Committee and a member of its Executive Steering Committee. Mr. Smith earned a Bachelor of Arts degree from the University of South Alabama and a Juris Doctor degree from The Ohio State University. Mr. Smith was selected to serve as a director because of his substantial knowledge of the energy industry and his business, leadership and management expertise. Mr. Smith is expected to serve as Senior Vice President and General Counsel of HoldCo effective at the time of the spin-off.

Stanley G. Chapman, III. Mr. Chapman will be appointed to our board of directors immediately prior to the date our common units are listed for trading on the NYSE. Mr. Chapman currently serves as our Chief Commercial Officer, a position he has held since December 2014. Mr. Chapman also serves as Executive Vice President and Chief Commercial Officer for various CEG subsidiaries, a position he has held since January 2014. Prior to that, he served as Senior Vice President of Marketing & Customer Services, a position he held since joining the company in December 2011. Prior to joining NiSource, Mr. Chapman was employed by El Paso Pipeline Company and its predecessor Tenneco Energy for nearly 23 years, where he last served as Vice President for Marketing, Business Development and Asset Optimization for its eastern pipelines. He currently is a member of the Interstate Natural Gas Association of America, the Southern Gas Association, and the North American Energy Standards Board where he holds various leadership and committee positions. Mr. Chapman earned a Bachelor of Science degree in Economics from Texas A&M University along with a Master of Business Administration from the University of St. Thomas. Mr. Chapman was selected to serve as a director because of his extensive knowledge of the energy industry and his leadership and management expertise. Mr. Chapman is expected to serve as Executive Vice President and Chief Commercial Officer of HoldCo effective at the time of the spin-off.

Thomas W. Hofmann. Mr. Hofmann will be appointed to our board of directors immediately prior to the date our common units are listed for trading on the NYSE. Upon his appointment, Mr. Hofmann will serve as chairman of our audit committee. Mr. Hofmann currently serves as a director of West Pharmaceutical Services, Inc., a position he has held since October 2007, and also as a director of Northern Tier Energy, LLC, a position he has held since May 2011. Mr. Hofmann served on the board of PVR Partners, L.P. from May 2009 through the March 2014 sale of PVR Partners to Regency Energy Partners LP. Mr. Hofmann is the retired Senior Vice President and Chief Financial Officer of Sunoco, Inc. (oil refining and marketing company), where he served in that capacity from January 2002 until December 2008. Mr. Hofmann earned a Master of Tax degree from Villanova University and a Bachelor of Science degree in Accounting from the University of Delaware. Mr. Hofmann was nominated to become a director because of his substantial knowledge of the industry and his business, leadership and management expertise.

Director Independence

In accordance with the rules of the NYSE, our sponsor must appoint at least one independent director prior to the listing of our common units on the NYSE, one additional member within three months of that listing, and one additional independent member within 12 months of that listing. Our general partner has reviewed the applicable independence standards established by the NYSE and the Exchange Act, and will appoint Mr. Hofmann as our initial independent director.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and will have the ability to establish a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will approve equity grants to directors and employees. The board may also have such other committees as they determine from time to time.

 

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Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following completion of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management.

Conflicts Committee

The board of directors of our general partner has the ability to establish a conflicts committee under our partnership agreement. The conflicts committee will consist of two or more members and will review specific matters that the board believes may involve conflicts of interest (including certain transactions with NiSource, CEG and HoldCo) or any other matters that the board refers to the committee. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including NiSource, HoldCo and CEG, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders.

 

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

Since our inception, we and our general partner have had no material assets or operations. Accordingly, our general partner has not accrued and will not accrue any obligations with respect to compensation of its directors and executive officers for any periods prior to the closing of this offering. Because the executive officers of our general partner are employed by our sponsor, compensation of the executive officers, other than the long-term incentive plan described below, will be set by our sponsor. The executive officers of our general partner will continue to participate in our sponsor’s employee benefit plans and arrangements, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers.

Our general partner will not receive a management fee or other compensation for its management of our partnership under the omnibus agreement with our sponsor or otherwise. Under the terms of our partnership agreement, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner or its affiliates in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses may include salary, bonus, incentive compensation and other amounts paid, if any, to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates” and “The Partnership Agreement—Reimbursement of Expenses.”

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business, and we do not have a compensation committee. We are managed by our general partner and our executive officers are employees of our sponsor. References to “our directors” refer to the directors of our general partner. We reimburse our sponsor for the services provided to us by our sponsor’s employees, including our executive officers. Our reimbursement is governed by our partnership agreement and will be based on our sponsor’s methodology used for allocating compensation expenses to us. We will be solely responsible for paying the expense associated with any awards granted under the long-term incentive plan described below which has been adopted by our general partner.

The compensation of our executive officers (other than long-term incentive plan benefits described below) is and will be determined and approved by our sponsor. We expect that our executive officers will not receive additional compensation for their service as such.

Long-Term Incentive Plan

In connection with the completion of this offering, our general partner will adopt the Columbia Pipeline Partners LP Long-Term Incentive Plan (“LTIP”), effective as of the date immediately preceding the closing of this offering, as described below. The LTIP will provide our general partner with maximum flexibility with respect to the design of compensatory arrangements for employees, officers, consultants, and directors of our general partner and any of its affiliates providing services to us; however, neither we nor our general partner currently have plans to make any grants under the LTIP in conjunction with this offering. Please see “—Compensation of Directors” below for information regarding plans for future grants of Phantom Unit Awards under the LTIP to the non-employee directors of our general partner.

Historical Compensation

As previously discussed, we are a wholly owned subsidiary of our sponsor formed to acquire, at the closing of this offering, portions of several different parts of our sponsor’s business. Neither we nor our general partner has incurred or will incur any cost or liability with respect to compensation of our executive officers prior to the closing of this offering. Accordingly, we have no historical compensation information to present.

 

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Long-Term Incentive Plan

The description of the LTIP set forth below is a summary of the material features of the plan our general partner has adopted. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, which is filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP provides for grants of (1) Restricted Units, (2) unit options, referred to as Options, (3) unit appreciation rights, referred to as UARs, (4) Phantom Units, (5) Unit Awards, (6) substitute awards, (7) other Unit-Based Awards, (8) cash awards, (9) performance awards and (10) distribution equivalent rights, referred to as DERs, collectively referred to as Awards.

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when Awards will be granted, determine the amount of Awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each Award agreement (the terms of which may vary), accelerate the vesting provisions associated with an Award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full Board or a subcommittee of two or more nonemployee directors will administer all Awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all Awards under the LTIP shall not exceed 9,000,000 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, as provided under the LTIP.

If a common unit subject to any Award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an Award or because an Award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to Awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Restricted Units. A Restricted Unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the Restricted Unit agreement, whether the Restricted Unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Unit with respect to which such common unit or other property has been distributed.

 

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Options. We may grant Options to eligible persons. Option Awards are options to acquire common units at a specified price. The exercise price of each Option granted under the LTIP will be stated in the Option agreement and may vary; provided, however, that, the exercise price for an Option must not be less than 100% of the fair market value per common unit as of the date of grant of the Option unless that Option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Options may be exercised in the manner and at such times as the committee determines for each Option, unless that Option is determined to be subject to Section 409A of the Code, where the Option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of an Option and the methods and forms in which common units will be delivered to a participant.

UARs. A UAR is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the UAR. The committee will be able to make grants of UARs and will determine the time or times at which a UAR may be exercised in whole or in part. The exercise price of each UAR granted under the LTIP will be stated in the UAR agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the UAR unless that UAR Award is intended to otherwise comply with the requirements of Section 409A of the Code.

Phantom Units. Phantom Units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject Phantom Units to restrictions (which may include a risk of forfeiture) to be specified in the Phantom Unit agreement that may lapse at such times determined by the committee. Phantom Units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the Phantom Unit, or any combination thereof determined by the committee. Except as otherwise provided by the committee in the Phantom Unit agreement or otherwise, Phantom Units subject to forfeiture restrictions may be forfeited upon termination of a Participant’s employment prior to the end of the specified period. Cash distribution equivalents may be paid during or after the vesting period with respect to a Phantom Unit, as determined by the committee.

Unit Awards. The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant Unit Awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Substitute Awards. The LTIP will permit the grant of Awards in substitution for similar awards held by individuals who become employees or directors as a result of a merger, consolidation, or acquisition by or involving us, an affiliate of another entity, or the assets of another entity. Such substitute Awards that are Options or UARs may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

Unit-Based Awards. The LTIP will permit the grant of other Unit-Based Awards, which are Awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, the Unit-Based Award may be paid in common units, cash or a combination thereof, as provided in the Award agreement.

Cash Awards. The LTIP will permit the grant of Awards denominated in and settled in cash. Cash Awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards. The committee may condition the right to exercise or receive an Award under the LTIP, or may increase or decrease the amount payable with respect to an Award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

 

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DERs. The committee will be able to grant DERs in tandem with Awards under the LTIP (other than an award of Restricted Units or Unit Awards), or DERs may be granted alone. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the DER is outstanding. Payment of a DER issued in connection with another Award may be subject to the same vesting terms as the Award to which it relates or different vesting terms, in the discretion of the committee.

Miscellaneous

Tax Withholding. At our discretion, and subject to conditions that the committee may impose, a participant’s minimum statutory tax withholding with respect to an Award may be satisfied by withholding from any payment related to an Award or by the withholding of common units issuable pursuant to the Award based on the fair market value of the common units.

Change in Control. Upon a “change of control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an Award, (ii) accelerate the time of exercisability or vesting of an Award, (iii) require Awards to be surrendered in exchange for a cash payment, (iv) cancel unvested Awards without payment or (v) make adjustments to Awards as the committee deems appropriate to reflect the change of control.

Termination of Employment or Service. The consequences of the termination of a grantee’s employment, consulting arrangement, or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

Compensation of Directors

Officers or employees of our sponsor or its affiliates who also serve as directors of our general partner will not receive additional compensation for such service. Our general partner anticipates that its directors who are not also officers or employees of our sponsor or its affiliates will receive compensation for services on our general partner’s board of directors and committees thereof. Following the completion of this offering, we expect our general partner to provide an annual retainer compensation package for the non-employee directors valued at approximately $150,000, of which approximately $60,000 would be paid in the form of an annual cash retainer and the remaining $90,000 retainer fee would be paid in a grant of Phantom Unit Awards under the LTIP.

In addition, our general partner expects to pay the audit committee chairman an annual amount of $20,000.

In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending board and committee meetings. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of common units and subordinated units of the Partnership that will be issued and outstanding upon the consummation of this offering and the related transactions and held by:

 

   

our general partner;

 

   

beneficial owners of 5% or more of our common units;

 

   

each director, director nominee and named executive officer; and

 

   

all of our directors, director nominees and executive officers as a group.

Unless otherwise noted, the address for each beneficial owner listed below is 5151 San Felipe St., Suite 2500, Houston, Texas 77056.

 

Name of Beneficial Owner

   Common Units
Beneficially
Owned
     Percentage of
Common Units
Beneficially
Owned
    Subordinated
Units
Beneficially
Owned
     Percentage of
Subordinated
Units
Beneficially
Owned
    Percentage of
Common and
Subordinated
Units
Beneficially
Owned
 

NiSource(1)

     6,811,398         14.6     46,811,398         100     57.3

CPP GP LLC

     —           —          —           —          —     

Robert C. Skaggs, Jr.

     —           —          —           —          —     

Glen L. Kettering

     —           —          —           —          —     

Stephen P. Smith

     —           —          —           —          —     

Robert E. Smith

     —           —          —           —          —     

Stanley G. Chapman, III

     —           —          —           —          —     

Thomas W. Hofmann

     —           —          —           —          —     

All executive officers, directors and director nominees as a group (6 persons)

     —           —          —           —          —     

 

(1)

The address of NiSource Inc. is 801 East 86th Avenue, Merrillville, IN 46410.

The following table sets forth, as of December 31, 2014, the number of shares of common stock of NiSource owned by each director, director nominee and named executive officer of our general partner and by all directors, director nominees and executive officers of our general partner as a group:

 

Name of Beneficial Owner

   Shares of Common
Stock Beneficially
Owned
    Percentage of
Common Stock
Beneficially
Owned
 

Robert C. Skaggs, Jr.

     736,274 (1)      *   

Glen L. Kettering

     85,374 (2)      *   

Stephen P. Smith

     131,100 (3)      *   

Robert E. Smith

     12,122 (4)      *   

Stanley G. Chapman, III

     1,867 (5)      *   

Thomas W. Hofmann

     —            

All executive officers, directors and director nominees as a group (6 persons)

     966,737          

 

* Less than 1%
(1) Does not include 128,370 shares underlying performance stock units that are subject to vesting in January 2015 to the extent that performance objectives are achieved.

 

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(2) Does not include 21,395 shares underlying performance stock units that are subject to vesting in January 2015 to the extent that performance objectives are achieved.

 

(3) Does not include 53,487 shares underlying performance stock units that are subject to vesting in January 2015 to the extent that performance objectives are achieved.

 

(4) Does not include 5,135 shares underlying performance stock units that are subject to vesting in January 2015 to the extent that performance objectives are achieved.

 

(5) Does not include 11,767 shares underlying performance stock units that are subject to vesting in January 2015 to the extent that performance objectives are achieved.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions

Prior to the offering, our predecessor was NiSource’s Columbia Pipeline Group Operations segment whose operations were conducted by wholly owned subsidiaries of NiSource and operated as a component of the integrated operations of NiSource and its affiliates. Consequently, we have historically engaged in significant transactions and have had material relationships with NiSource and its affiliates on a continuous basis.

Ownership of General Partner and Limited Partner Interests

Following the completion of this offering, CEG will own 85.4% of the limited partner interests in Columbia OpCo. In addition, CEG will beneficially own approximately 14.6% of our common units, or 12.9% if the underwriters exercise their option to purchase additional common units in full, all of our subordinated units and all of our incentive distribution rights. In addition, following completion of this offering, CEG will own the entire equity interest in our general partner. As a result, CEG will continue to be able to control the election of the directors of our general partner, otherwise exercise control or significant influence over our partnership and management policies and generally determine the outcome of any partnership or Columbia OpCo transaction or other matter submitted to our unitholders for approval, including potential mergers or acquisitions, asset sales and other significant partnership transactions. So long as CEG owns a majority equity interest in our general partner, CEG will continue to be able to effectively control the outcome of such matters. So long as NiSource controls CEG, it will indirectly control us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

 

The aggregate consideration received by CEG and its affiliates for the contribution of an interest in Columbia OpCo and our purchase of an interest in Columbia OpCo

  6,811,398 common units;

 

   

all 46,811,398 subordinated units;

 

   

our incentive distribution rights; and

 

   

we will use the $755.0 million of net proceeds from this offering (after deducting the underwriting discount, the structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and expenses of this offering) to purchase an additional approximate 6.2% limited partner interest in Columbia OpCo, and Columbia OpCo will use $500.0 million of these net proceeds to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures. The approximate 6.2% interest in Columbia OpCo purchased with the proceeds from this offering, when combined with an approximate 8.4% interest in Columbia OpCo contributed to us in connection

 

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with the formation transactions, will result in our ownership of a 14.6% limited partner interest in Columbia OpCo following the closing of the offering.

 

  To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and use the net proceeds to purchase an additional percentage limited partner interest in Columbia OpCo, and Columbia OpCo will use such cash to fund expansion capital expenditures. The amount of the additional interest in Columbia OpCo purchased will depend on the number of common units issued pursuant to the exercise of such option, and will be calculated at approximately 0.16% additional limited partner interest in Columbia OpCo purchased for each one million of additional common units purchased by the underwriters. If the underwriters exercise their option to purchase additional common units in full, we would purchase an additional 1.0% limited partner interest in Columbia OpCo and our total ownership interest in Columbia OpCo would be 15.6%.

Operational Stage

 

Distributions of cash available for distribution to our general partner and its affiliates

We will generally make cash distributions of 100% of our available cash to the common and subordinated unitholders, including affiliates of our general partner, as holders of an aggregate of 6,811,398 common units (7.3% of all units outstanding), and all of our subordinated units (50.0% of all units outstanding). In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the incentive distribution rights held by CEG will entitle CEG to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.

 

  Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $35.9 million on their common and subordinated units (or $35.9 million if the underwriters exercise in full their option to purchase additional common units).

 

Payments to our general partner and its affiliates

Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

 

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Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest and CEG’s incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

 

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Arrangements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including our acquisition of interests in Columbia OpCo, the vesting of assets in, and the assumption of liabilities by, us and Columbia OpCo, and the application of the proceeds of this offering, and we have entered into or are entering into a number of other agreements with CEG and its affiliates. These agreements are not and will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into Columbia OpCo, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with CEG, our general partner, Columbia OpCo and others that will address CEG’s obligation to indemnify us for certain liabilities and our obligation to indemnify CEG for certain liabilities.

Our general partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “—Contracts with Affiliates.”

Reimbursement of General and Administrative Expenses

Under the omnibus agreement, CEG will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, we will reimburse CEG and its affiliates for the expenses incurred by them in providing these services. The omnibus agreement will further provide that we will reimburse CEG and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets.

We will also reimburse CEG for any additional state income, margin or similar tax paid by CEG resulting from the inclusion of us (and our subsidiaries) in a combined state income, margin or similar tax return with CEG as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with CEG.

 

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Our Right of First Offer for CEG’s Interest in Columbia OpCo

Under the omnibus agreement, CEG will be required to offer us the right to purchase its 85.4% limited partner interest in Columbia OpCo, before it can sell that interest to anyone else. We refer to our purchase right as a right of first offer. The completion and timing of any future purchases by us of any part of CEG’s interest in Columbia OpCo will depend upon, among other things, CEG’s decision to sell its interest in Columbia OpCo, our ability to reach an agreement with CEG regarding the price and other terms of such purchase, compliance with our debt agreements, and our ability to obtain financing on acceptable terms. Although we will have the right of first offer to purchase CEG’s interest in Columbia OpCo, we are not obligated to purchase any additional interest in Columbia OpCo from CEG.

Pursuant to the omnibus agreement, CEG must give us written notice of its intent to sell all or a portion of its 85.4% interest in Columbia OpCo, specifying the fundamental terms of the proposed sale, other than the sale price. Within 45 days of receiving such notification from CEG, the conflicts committee of our general partner must notify CEG in writing whether we wish to make an offer to purchase the interest to be sold, and, if so, provide the price we are willing to pay for the interest. Thereafter, our conflicts committee and CEG will enter into good faith negotiations for a 45-day period to reach an agreement for us to purchase the interest offered for sale. If our conflicts committee and CEG cannot agree on the terms of purchase for the interest offered for sale after negotiating in good faith for the 45-day period, CEG may give us notice that it rejects our offer and will thereafter seek an alternative purchase. In the event CEG is thereafter able to obtain a good faith, binding offer to pay at least 105% of the highest purchase price (on a present value basis) we proposed or as contained in any greater written offer made by us during the 45-day negotiation period, then CEG will be free to sell the interest at such greater price. If an alternative transaction complying with the provisions set out immediately above has not been consummated by CEG within 270 days after the end of our 45-day negotiation period, the right of first offer would be reinstated and would apply to any future sale or future offer by CEG to sell all or a portion of their interest.

Spin-Off Covenant

Under the omnibus agreement, we will agree to refrain for two years from taking any actions that could cause HoldCo to violate its covenants under the tax sharing agreement that HoldCo may enter into with NiSource in connection with the spin-off. In addition, we will agree not to take any action that could cause HoldCo to violate one of the covenants in the tax sharing agreement. We will indemnify CEG for losses attributable to our breach of those covenants.

Competition

Neither NiSource nor any of its affiliates will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. NiSource and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or contract those assets.

Indemnification

Under the omnibus agreement, CEG will indemnify us for three years after the closing of this offering against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before the closing date of this offering. The maximum liability of CEG for this indemnification obligation will not exceed $15 million and CEG will not have any obligation under this indemnification until our aggregate losses exceed $250,000. CEG will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws relating to pollution or protection of the environment or natural resources promulgated after the closing date of this offering. We have agreed to indemnify CEG against environmental liabilities related to our assets to the extent CEG is not required to indemnify us.

 

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Additionally, CEG will indemnify us for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify CEG for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to CEG’s indemnification obligations.

Guarantees

Under the omnibus agreement, when requested by HoldCo, Columbia OpCo will be required to guarantee any future indebtedness that HoldCo incurs. In addition, at our request, HoldCo and Columbia OpCo will be required to guarantee any future indebtedness that the Partnership incurs. The Partnership’s decision on whether to request a guarantee from HoldCo and/or Columbia OpCo will be determined by a majority of the members of the conflicts committee of the board of directors of our general partner. In the event either HoldCo or Columbia OpCo is required to make payment under its respective guarantee, such guarantor will be subrogated to the rights of the respective lenders.

Contracts with Affiliates

Services Agreement

We have entered into a service agreement with Columbia Pipeline Group Services Company. Pursuant to this agreement, Columbia Pipeline Group Services Company will perform centralized corporate functions for us, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. We will reimburse Columbia Pipeline Group Services Company for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of their employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes, and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.

Trademark License Agreement

Under the Trademark License Agreement between NiSource Corporate Services Company (“NiSource Corporate Services”) and Columbia Pipeline Group Services Company, our affiliate, Columbia Pipeline Group Services Company and its present and future affiliates receive a royalty-free, perpetual, irrevocable, exclusive license to use licensed marks within the United States in connection with natural gas and oil services (the “Licensed Marks”). Licensed Marks include any registered or unregistered trademarks, trade names, logos, and/or service marks owned by NiSource Corporate Services or its affiliates containing the term “COLUMBIA.”

The Trademark License Agreement contains certain limitations on the license grant described above, including restrictions on sublicensing rights to use the Licensed Marks and requirements to comply with certain quality control standards. NiSource Corporate Services retains the right to sue for infringement of the Licensed Marks unless Licensor fails to act within 90 days of receiving notice of infringement or fails to diligently prosecute an infringement suit. The term of the Trademark License Agreement is perpetual and can only be terminated by mutual written agreement of the parties.

Transportation Related Arrangements

We charge transportation fees to five NiSource subsidiaries. Management anticipates continuing to provide these services to these NiSource subsidiaries in the ordinary course of business. We are party to firm transportation and storage contracts with Columbia Gas of Kentucky, Columbia Gas of Maryland, Columbia Gas of Ohio, Columbia Gas of Pennsylvania and Columbia Gas of Virginia. All of these contracts have terms that expire between 2014 and 2027. Columbia Gas Transmission also has off-system leases with affiliates Millennium Pipeline and Columbia Gulf, while Millennium Pipeline has an off-system lease with Columbia Gas Transmission. Columbia Gas Transmission has firm contracts with Millennium Pipeline and Columbia Gulf has

 

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interruptible contracts with Columbia Gas Transmission. Additionally, Columbia Gas Transmission has operational balancing agreements (“OBAs”) with each of Columbia Gulf, Hardy Storage, Millennium Pipeline, Columbia Midstream and Crossroads Pipeline. OBAs are a typical agreement between interconnecting pipelines.

Columbia OpCo Partnership Agreement and OpCo GP Limited Liability Company Agreement

We, CPG OpCo GP LLC (“OpCo GP”) and CEG have entered into a limited partnership agreement for Columbia OpCo. This agreement governs the ownership and management of Columbia OpCo and, designates OpCo GP as the general partner of Columbia OpCo. OpCo GP will generally have complete authority to manage Columbia OpCo’s business and affairs. We will control OpCo GP, as its sole member.

Approval from CEG will be required for the following actions relating to Columbia OpCo:

 

   

effecting any merger or consolidation involving Columbia OpCo;

 

   

effecting any sale or exchange of all or substantially all of Columbia OpCo’s assets;

 

   

dissolving or liquidating Columbia OpCo;

 

   

creating or causing to exist any consensual restriction on the ability of Columbia OpCo or its subsidiaries to make distributions, pay any indebtedness, make loans or advances or transfer assets to us or our subsidiaries;

 

   

settling or compromising any claim, dispute or litigation directly against, or otherwise relating to indemnification by Columbia OpCo of, any of the officers of OpCo GP; or

 

   

issuing additional partnership interests in Columbia OpCo.

Additionally, we will have a preemptive right under the Columbia OpCo partnership agreement to acquire additional limited partner interests in Columbia OpCo in connection with its issuance of any new equity interests.

In addition, OpCo GP will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase partnership interests from Columbia OpCo whenever, and on the same terms, that Columbia OpCo issues partnership interests to persons other than OpCo GP or its affiliates.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Summary of Applicable Duties

The Delaware Act provides that, to the extent that, at law or in equity, a partner or other person has duties (including fiduciary duties) to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement, the partner’s or other person’s duties may be expanded or restricted or eliminated by provisions in the partnership agreement, provided that the Delaware Act provides that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner and its executive officers and directors would otherwise be held by state fiduciary duty law. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Columbia OpCo partnership agreement also eliminates and replaces the fiduciary standards to which we and OpCo GP would otherwise be held to owe CEG, as a limited partner in Columbia OpCo, by state fiduciary duty law and specifically defines the remedies available to CEG for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must not act in “bad faith,” meaning it must not act in a manner that it believes is not adverse to our interest. This duty not to act in bad faith is the default standard set forth under our partnership agreement and our general partner and its officers and directors will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity, and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to act, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to our sponsor.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to not act in bad faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interest. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers and owners (including our sponsor), on the one hand, and us and our unaffiliated limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the determination, action or omission in respect of such conflict of interest shall be

 

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conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution, course of action or transaction in respect of such conflict of interest is:

 

   

approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or

 

   

approved by the holders of a majority of our outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such determination, action or omission from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the determination, action or omission taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith,” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such determination was not in good faith. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

   

amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings;

 

   

entry into and repayment of current and future indebtedness;

 

   

issuance of additional units; and

 

   

the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to holders of our incentive distribution rights and the ability of the subordinated units to convert into common units.

 

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In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 

   

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

 

   

accelerating the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $62 million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions to Our Partners.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions to Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

The directors and officers of our sponsor have a fiduciary duty to make decisions in the best interests of the owners of our sponsor, which may be contrary to our interests.

The officers and certain directors of our general partner have fiduciary duties to our sponsor that may cause them to pursue business strategies that disproportionately benefit our sponsor or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

Our partnership agreement restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

 

   

our general partner and its executive officers and directors will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it did not act in bad faith, meaning it did not believe that the decision was adverse to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

 

   

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

 

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in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, the purchaser agrees to be bound by the provisions in our partnership agreement.

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

 

   

expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

 

   

making tax, regulatory and other filings, or rendering periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

   

acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

 

   

negotiating, executing and performing contracts, conveyances or other instruments;

 

   

distributing cash or property;

 

   

selecting, employing or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

 

   

maintaining insurance for our benefit;

 

   

forming, acquiring an interest in, and contributing property and loaning money to, any partnerships, joint ventures, corporations, limited liability companies or other entity (including firms, trusts and unincorporated organizations);

 

   

controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

 

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indemnifying any person against liabilities and contingencies to the extent permitted by law;

 

   

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative interests relating to, convertible into or exchangeable for our partnership interests; and

 

   

entering into agreements with any of its affiliates, including to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the price calculated in accordance with the terms of our partnership agreement. Please read “Risk Factors—Risks Inherent in an Investment in Us—Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.” and “The Partnership Agreement—Limited Call Right.”

We may choose not to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our sponsor. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Please read “Risk Factors—Risks Inherent in an Investment in Us—Our sponsor and other affiliates of our general partner may compete with us.”

 

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The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of target distribution levels related to the incentive distribution rights, without the approval of our unitholders. This election could result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated to be an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that CEG would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, CEG may transfer the incentive distribution rights at any time. It is possible that CEG or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions they receive related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on initial target distribution levels. As a result, a reset election may cause our common unitholders to experience reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions to Our Partners—IDR Holders’ Right to Reset Incentive Distribution Levels.”

Columbia OpCo will be a restricted subsidiary and a guarantor under HoldCo’s credit facility and, if requested by HoldCo, will guarantee future HoldCo indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

All of our cash will be generated from cash distributions from Columbia OpCo. In connection with the spin-off, HoldCo expects to issue a significant amount of new senior indebtedness. Under the omnibus agreement, at HoldCo’s request Columbia OpCo will guarantee future indebtedness of HoldCo. To the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant operating and financial restrictions. For example, these restrictions could include covenants limiting Columbia OpCo’s ability to:

 

   

make investments and other restricted payments;

 

   

incur additional indebtedness or issue preferred stock;

 

   

create liens;

 

   

sell all or substantially all of its assets or consolidate or merge with or into other companies; and

 

   

engage in transactions with affiliates.

These covenants could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. A breach by HoldCo of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing

 

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that debt, including Columbia OpCo and its assets. In addition, any acceleration of debt under HoldCo’s bank syndicated credit facility could constitute a default under other HoldCo debt, which Columbia OpCo may also guarantee. If HoldCo’s lenders or other debt creditors were to proceed against Columbia OpCo’s assets, the value of our ownership interests in Columbia OpCo could be significantly reduced, which could adversely affect the value of our common units.

Additionally, in the future HoldCo may determine that it is in its best interest to agree to more restrictive covenants or to pledge assets. HoldCo would not owe us or our unitholders any fiduciary duty in allocating exceptions or baskets to covenants and financial ratios among itself and its guarantors, or in amending its debt agreements to include provisions more burdensome to our operations and financing capabilities.

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers with contractual standards governing the duties of our general partner and contracted methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership not in bad faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

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Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates (including its directors and executive officers) that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must not act in “bad faith,” meaning that it must not believe its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.

 

  In making decisions, other than one where our general partner is permitted to act in its sole discretion, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.

 

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. Under our partnership agreement, any unitholder that brings an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

 

Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement.

 

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By purchasing a common unit, the purchaser automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Distributions to Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Restrictions on Ownership of Common Units

In order to comply with certain of the FERC’s rate-making policies applicable to entities like us that pass their taxable income through to their owners, we have adopted requirements regarding who can be our owners. Our partnership agreement requires that purchasers of our common units, including those who purchase common units from underwriters, represent that they are Eligible Holders (as defined in our partnership agreement). Our general partner may require any owner of our units to recertify its status as an Eligible Holder. If a unitholder is an Ineligible Holder (as defined in our partnership agreement), the unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we will have the right to redeem such units at a price equal to the lower of the unitholder’s purchase price or the then-current market price of such units, calculated in accordance with a formula specified in our partnership agreement. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “—Transfer of Common Units” and “The Partnership Agreement—Non-Taxpaying Holders; Redemption.”

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our unitholders:

 

   

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

   

special charges for services requested by a holder of a common unit; and

 

   

other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

 

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Transfer of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee, with or without executing the partnership agreement:

 

   

represents that the transferee has the capacity, power and authority to be bound by our partnership agreement;

 

   

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

   

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

   

with regard to distributions of cash available for distribution, please read “How We Make Distributions to Our Partners”;

 

   

with regard to the duties of, and standard of care applicable to, our general partner and its executive officers and directors, please read “Conflicts of Interest and Fiduciary Duties”;

 

   

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

 

   

with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Columbia Pipeline Partners LP was organized in December 2007 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of transporting, storing, gathering and processing natural gas, our general partner has no current plans to do so and may decline to do so in its sole discretion. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to CEG in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions to Our Partners.”

 

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require:

 

   

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units whose voting power is, for purposes of the applicable matter for which a vote is being taken, beneficially owned by our general partner or its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

 

   

after the subordination period, the approval of a majority of the outstanding common units.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

 

Issuance of additional units

No unitholder approval right.

 

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please read “—Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to March 31, 2025 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Please read “—Withdrawal or Removal of Our General Partner.”

 

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Transfer of our general partner interest

No unitholder approval right. Please read “—Transfer of General Partner Interest.”

 

Transfer of incentive distribution rights

No unitholder approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

 

Transfer of ownership interests in our general partner

No unitholder approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Exclusive Jurisdiction; Reimbursement of Litigation Costs

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

   

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

   

brought in a derivative manner on our behalf;

 

   

asserting a claim of breach of a duty (including a fiduciary duty) owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

   

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

   

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims.

Our partnership agreement provides that if any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

 

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

 

   

to remove or replace our general partner;

 

   

to approve some amendments to our partnership agreement; or

 

   

to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Following the completion of this offering, we expect that our subsidiaries will conduct business in several states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

 

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Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any express covenant, duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

   

enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

   

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately 57.3% of our outstanding common and subordinated units (or 53.8% of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units).

 

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No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

   

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

   

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

   

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

 

   

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed;

 

   

an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

 

   

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

   

an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

 

   

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

   

a change in our fiscal year or taxable year and related changes;

 

   

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

   

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

   

do not adversely affect in any material respect the limited partners (including any particular class of limited partners as compared to other classes of limited partners);

 

   

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

   

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

   

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of

 

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counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

 

   

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

   

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

   

the entry of a decree of judicial dissolution of our partnership; or

 

   

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

   

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

   

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions to Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to March 31, 2025 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after March 31, 2025, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

 

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Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, an affiliate of our general partner will own 14.6% of our outstanding common units and all of our subordinated units (or 12.9% of the outstanding common units and all of our subordinated units, if the underwriters exercise in full their option to purchase additional common units).

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

 

   

all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

 

   

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner and the incentive distribution rights of its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and the incentive distribution rights of its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and the incentive distribution rights of its affiliates will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

 

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Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

At any time, our general partner and the holder or holders of our incentive distribution rights (initially our sponsor) may sell or transfer its subordinated units or their incentive distribution rights, as applicable, to an affiliate or third party without the approval of the unitholders. By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

   

represents that the transferee has the capacity, power and authority to be bound by our partnership agreement;

 

   

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

   

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove CPP GP LLC as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

 

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Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

 

   

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

   

the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Meetings; Voting

Except as described below, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 25% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

 

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Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Ineligible Holders; Redemption

Under our partnership agreement, an “Ineligible Holder” is a limited partner, or type of limited partner, whose, or whose owners’, in the determination of our general partner with the advice of counsel (a) U.S. federal income tax status creates or is reasonably likely to create a substantial risk of an adverse effect on the rates that can be charged to our customers by us with respect to assets that are subject to regulation by FERC or a similar regulatory body or (b) nationality, citizenship or other related status would create or is reasonably likely to create a substantial risk of cancellation or forfeiture of any property in which we have an interest. A list of types of unitholders and whether they are of the type currently determined by our general partner to be Eligible Holders or Ineligible Holders is included in this prospectus as Appendix B. Our general partner may change its determination of what types of unitholders are considered Eligible Holders and Ineligible Holders at any time. We will make an updated list of such types of unitholders available to our unitholders and prospective unitholders.

If at any time our general partner determines, with the advice of counsel, that one or more limited partners are Ineligible Holders, then our general partner may request any limited partner to furnish to our general partner an executed certification or other information about its federal income tax status and/or nationality, citizenship or related status. If a limited partner fails to furnish such certification or other requested information within 30 days (or such other period as our general partner may determine) after a request for such certification or other information, or our general partner determines after receipt of the information that the limited partner is an

 

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Ineligible Holder, the limited partner may be treated as an Ineligible Holder. An Ineligible Holder does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of the common and subordinated units of any holder that our general partner concludes is an Ineligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

   

our general partner;

 

   

any departing general partner;

 

   

any person who is or was an affiliate of our general partner or any departing general partner;

 

   

any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

   

any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries;

 

   

any person who controls our general partner or any departing general partner; and

 

   

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those

 

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consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

 

   

a current list of the name and last known address of each record holder;

 

   

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; and

 

   

certain information regarding the status of our business and financial condition.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights will continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding the underwriting discount.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with our sponsor. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to our sponsor and the common units issuable upon the conversion of the subordinated units upon request of our sponsor. In addition, the registration rights agreement gives our sponsor piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of our sponsor and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, our sponsor will hold an aggregate of 6,811,398 common units and 46,811,398 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. For information regarding the conversion of subordinated units into common units prior to the end of the subordination period, please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.” The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1% of the total number of the securities outstanding; or

 

   

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

The executive officers and directors of our general partner and our sponsor have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

 

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Prior to the completion of this offering, we expect to adopt a new LTIP. If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the LTIP will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “we” or “us” are references to Columbia Pipeline Partners LP and our operating subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the U.S. (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (i) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We will be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its units.

 

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Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the processing, transportation, storage and marketing of certain natural resources, including products of natural gas, as well as other types of qualifying income such as interest (other than from a financial business) and dividends. We estimate that less than 3% of our current gross income is not qualifying income; however, this estimate could change from time to time.

Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership for federal income tax purposes and each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected to be treated as a corporation for federal income tax purposes; and

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the distributable cash flow to unitholders and thus would likely substantially reduce the value of our common units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

 

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Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in its share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2017, will be allocated, on a cumulative basis, an amount of federal taxable income that will be less than 20% of the cash expected to be distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the anticipated quarterly distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates.

The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

   

we distribute less cash than we have assumed in making this projection; or

 

   

we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness

 

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outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes during such period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

For each taxable year ending on or before December 31, 2021, holders of common units (excluding common units held by CEG or its affiliates) will be allocated additional gross operating income; provided that no such special allocation shall be made to the extent a purchaser of common units in this offering would be allocated an amount of federal taxable income on the common units purchased in this offering with respect to such taxable year that would exceed 20% of the cash distributed on the common units purchased in this offering with respect to such year.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “liabilities” will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk

 

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amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

   

interest on indebtedness allocable to property held for investment;

 

   

interest expense allocated against portfolio income; and

 

   

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income generally includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income. Net investment income does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Except as described below, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or we make incentive distributions, gross

 

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income will be allocated to the recipients to the extent of these distributions. In addition, for each taxable year ending on or before December 31, 2021, holders of common units (excluding converted subordinated units held by CEG or its affiliates) will be allocated additional gross operating income; provided that no such special allocation shall be made to the extent a purchaser of common units in this offering would be allocated an amount of federal taxable income on the common units purchased in this offering with respect to such taxable year that would exceed 20% of the cash distributed on the common units purchased in this offering with respect to such year. Items of gain and loss and, in certain circumstances, income and deduction may be allocated among the partners in a manner to create economic uniformity among the common units held by CEG, common units into which the subordinated units convert and the common units held by public unitholders.

Specified items of our income, gain, loss and deduction generally will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our common units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to consult their own tax advisors and to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

 

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In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation, to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain,

 

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loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax bases of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discount we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both

 

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ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of the units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

 

   

a short sale;

 

   

an offsetting notional principal contract; or

 

   

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury

 

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Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31, except as described below, would require that we file two tax returns for one fiscal year, thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

 

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Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations, as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or Non-U.S. Unitholders should consult their tax advisors before investing in our units.

Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. Unitholders are taxed by the U.S. on income effectively connected with a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty, and will be treated as engaged in business in the U.S. because of their ownership of our common units. Furthermore, it is probable that they will be deemed to conduct such activities through permanent establishment in the U.S. within the meaning of any applicable tax treaty. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a Non-U.S. Unitholder classified as a corporation will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain recognized by a Non-U.S. Unitholder from the sale of its interest in a partnership that is engaged in a trade or business in the U.S. will be considered to be “effectively connected” with

 

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a U.S. trade or business. Thus, part or all of a Non-U.S. Unitholder’s gain from the sale or other disposition of units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a Non-U.S. Unitholder will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or indirectly constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of our real property interests and other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate, including land, improvements, and associated personal property, and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, Non-U.S. Unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

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Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in those jurisdictions. We will initially own assets and conduct business in various states, each of which imposes a personal income tax on individuals and an income tax on corporations and other entities. We may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of the unitholder’s investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

 

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INVESTMENT IN COLUMBIA PIPELINE PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

   

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

   

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

   

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(2) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(3) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

Barclays Capital Inc. and Citigroup Global Markets Inc. are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

 

Underwriter

   Number of
Units
 

Barclays Capital Inc.

  

Citigroup Global Markets Inc.

  

Merrill Lynch, Pierce, Fenner & Smith

                      Incorporated

  

Goldman, Sachs & Co.

  

J.P. Morgan Securities LLC

  

Morgan Stanley & Co. LLC

  

Wells Fargo Securities, LLC

  

BNP Paribas Securities Corp.

  

Credit Suisse Securities (USA) LLC

  

RBC Capital Markets, LLC

  

Fifth Third Securities, Inc.

  

KeyBanc Capital Markets Inc.

  

Mitsubishi UFJ Securities (USA), Inc.

  

Mizuho Securities USA Inc.

  

Scotia Capital (USA) Inc.

  

The Huntington Investment Company

  
  

 

 

 

Total

     40,000,000   
  

 

 

 

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters’ over-allotment option described below) if they purchase any of the common units.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $         per common unit. After the common units are released for sale to the public, if all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 6,000,000 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, CEG, our general partner and the executive officers and directors of our general partner, have agreed that, subject to certain exceptions, for a period of 180 days from the date of this prospectus, we and they will not,

 

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without the prior written consent of each of Barclays Capital Inc. and Citigroup Global Markets Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Barclays Capital Inc. and Citigroup Global Markets Inc., in their sole discretion, may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our partnership occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event. Neither Barclays Capital Inc. nor Citigroup Global Markets Inc. has any present intention or any understanding, implicit or explicit, to release any of the common units or other securities subject to the lock-up agreement prior to the expiration of the 180-day restricted period described above.

At our request, the underwriters have reserved up to 5% of the common units for sale at the initial public offering price to persons who are directors, officers or employees of our general partner and its affiliates and certain other persons associated with us, as designated by us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. Except for certain of the officers and directors of our general partner who have entered into lock-up agreements as contemplated in the immediately preceding paragraph, each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Barclays Capital Inc. and Citigroup Global Markets Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units with respect to units purchased in the program. For certain officers and directors of our general partner purchasing common units through the directed unit program, the lock-up agreements contemplated in the immediately preceding paragraph shall govern with respect to their purchases. Barclays Capital Inc. and Citigroup Global Markets Inc. in their sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors of our general partner, shall be with notice. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We have applied for listing on the NYSE under the symbol “CPPL.”

The following table shows the underwriting discount that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

 

Total Expenses

   No Exercise      Full Exercise  

Per common unit

   $                    $                

Total

   $         $     

 

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We will pay Barclays Capital Inc. and Citigroup Global Markets Inc. an aggregate structuring fee equal to 0.5% of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership. We have also agreed to reimburse the underwriters for up to $20,000 of reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc. (“FINRA”) of the terms of sale of the common units offered hereby.

We estimate that the expenses of this offering, not including the underwriting discount and structuring fee, will be approximately $5.0 million, all of which will be paid by us.

In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ option to purchase additional common units, and stabilizing purchases.

 

   

Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering.

 

   

“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ over-allotment option.

 

   

“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ over-allotment option.

 

   

Covering transactions involve purchases of common units either pursuant to the underwriters’ over-allotment option or in the open market after the distribution has been completed in order to cover short positions.

 

   

To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering.

 

   

To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the underwriters’ over-allotment option.

 

   

Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Conflicts of Interest

Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, CEG and our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses.

 

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Additionally, affiliates of each of the underwriters are lenders under our new revolving credit facility. Certain of the underwriters or their affiliates have performed or will perform commercial banking, investment banking and advisory services for us, CEG and our respective affiliates during the 180-day period prior to, or the 90-day period following, the date of this prospectus, for which they have received or will receive customary fees and reimbursement of expenses. Additionally, affiliates of Barclays Capital Inc. and Citigroup Global Markets Inc. have provided advisory services in connection with the spin-off of HoldCo and will receive customary fees in connection with such services.

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments, and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments.

Because the FINRA views the common units offered hereby as interests in a direct participation program, there is no conflict of interest between us and the underwriters under Rule 5121 of the FINRA Rules and this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

We, our general partner and certain of our affiliates, including CEG, have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

 

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VALIDITY OF OUR COMMON UNITS

The validity of our common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of the Predecessor as of December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013 included in this Prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such combined financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of the Partnership as of June 30, 2014 included in this Prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. For further information regarding us and our common units offered in this prospectus, we refer you to the registration statement and the exhibits and schedule filed as part of the registration statement. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website address on the Internet will be http://www.columbiapipelinepartners.com, and we intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. After this offering, documents filed by us can also be inspected at the offices of the New York Stock Exchange Inc., 20 Broad Street, New York, New York 10002.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

 

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

   

changes in general economic conditions;

 

   

competitive conditions in our industry;

 

   

actions taken by third-party operators, processors and transporters;

 

   

the demand for natural gas storage and transportation services;

 

   

our ability to successfully implement our business plan;

 

   

our ability to complete internal growth projects on time and on budget;

 

   

the price and availability of debt and equity financing;

 

   

the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

 

   

competition from the same and alternative energy sources;

 

   

energy efficiency and technology trends;

 

   

operating hazards and other risks incidental to transporting, storing and gathering natural gas;

 

   

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

   

interest rates;

 

   

labor relations;

 

   

large customer defaults;

 

   

changes in the availability and cost of capital;

 

   

changes in tax status;

 

   

the effects of existing and future laws and governmental regulations;

 

   

the effects of future litigation; and

 

   

certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

 

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INDEX TO FINANCIAL STATEMENTS

 

Columbia Pipeline Partners LP

  

Unaudited Pro Forma Combined Financial Statements

  

Introduction

     F-2   

Pro Forma Combined Balance Sheet as of September 30, 2014

     F-4   

Pro Forma Combined Statement of Operations for the Year Ended December 31, 2013

     F-6   

Pro Forma Combined Statement of Operations for the Nine Months Ended September 30, 2014

     F-7   

Notes to Unaudited Pro Forma Combined Financial Statements

     F-8   

Audited Balance Sheet

  

Report of Independent Registered Public Accounting Firm

     F-12   

Balance Sheet as of June 30, 2014

     F-13   

Note to the Balance Sheet

     F-14   

Unaudited Balance Sheet

  

Balance Sheet as of September 30, 2014

     F-15   

Note to the Balance Sheet

     F-16   

Columbia Pipeline Partners LP Predecessor

  

Unaudited Interim Financial Statements

  

Condensed Combined Balance Sheets as of September 30, 2014 and December 31, 2013

     F-17   

Condensed Combined Statements of Operations for the Nine Months Ended September 30, 2014 and  2013

     F-19   

Condensed Combined Statements of Comprehensive Income for the Nine Months Ended September  30, 2014 and 2013

     F-20   

Condensed Combined Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013

     F-21   

Condensed Combined Statements of Parent Net Equity for the Nine Months Ended September  30, 2014 and 2013

     F-22   

Notes to Condensed Combined Financial Statements

     F-23   

Audited Historical Financial Statements

  

Report of Independent Registered Public Accounting Firm

     F-33   

Combined Balance Sheets as of December 31, 2013 and 2012

     F-34   

Combined Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011

     F-36   

Combined Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and  2011

     F-37   

Combined Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

     F-38   

Combined Statements of Parent Net Equity for the Years Ended December 31, 2013, 2012 and 2011

     F-39   

Notes to Combined Financial Statements

     F-40   

 

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Columbia Pipeline Partners LP

Unaudited Pro Forma Combined Financial Statements

for the Year Ended December 31, 2013 and the Nine Months Ended September 30, 2014

Columbia Pipeline Partners LP (the “Partnership”) is a Delaware limited partnership that was formed on December 5, 2007 by NiSource Inc. (“NiSource”) to own, operate and develop a portfolio of pipelines, storage and related assets. NiSource intends to offer common units representing limited partner interests in the Partnership to the public (the “offering”).

At the completion of the offering, NiSource will indirectly own (i) a non-economic general partner interest in the Partnership through CPP GP LLC (“MLP GP”), an indirect wholly owned subsidiary of NiSource and the general partner of the Partnership, (ii) a 57.3% limited partner interest in the Partnership and (iii) all of the incentive distribution rights in the Partnership. The Partnership will own a 14.6% limited partner interest in CPG OpCo LP (“Columbia OpCo”), which is a Delaware limited partnership formed by Columbia Energy Group, a wholly owned subsidiary of NiSource, and CPG OpCo GP LLC, a wholly owned subsidiary of the Partnership (“OpCo GP”). NiSource will retain the remaining 85.4% limited partner interest in Columbia OpCo. OpCo GP will be Columbia OpCo’s general partner and will control its assets and operations. As part of the offering, NiSource will contribute, or will cause the contribution of, to Columbia OpCo its interest in the following wholly-owned subsidiaries: Columbia Gas Transmission, LLC, Columbia Gulf Transmission, LLC, Columbia Midstream Group, LLC, Columbia Energy Ventures, LLC, and CNS Microwave, Inc. Equity method investments in Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C., and Pennant Midstream, LLC will also be contributed to Columbia OpCo.

Unless the context requires otherwise, for purposes of this pro forma presentation, all references to “we”, “our”, “us” and the “Partnership” refer to Columbia Pipeline Partners LP and its subsidiaries, including Columbia OpCo. Columbia OpCo’s financial information will be consolidated with the Partnership because the Partnership, through ownership of Columbia OpCo’s general partner, will control Columbia OpCo upon completion of the offering.

The unaudited pro forma financial statements of the Partnership are based on the historical financial statements of Columbia Pipeline Partners LP Predecessor (the “Predecessor”), which comprises all of NiSource’s Columbia Pipeline Group Operations’ reportable segment. The unaudited pro forma combined statements of operations for the year ended December 31, 2013 and for the nine months ended September 30, 2014 assume the offering and related transactions occurred on January 1, 2013. The unaudited pro forma combined balance sheet as of September 30, 2014 assumes the offering and related transactions occurred on September 30, 2014. The unaudited pro forma combined financial statements do not present the Partnership’s actual results of operations had the offering and related transactions been completed at the dates indicated. In addition, they do not project the Partnership’s results of operations for any future period. The unaudited pro forma combined financial statements reflect the following significant assumptions and transactions:

 

   

the assumption by CEG, the Partnership’s sponsor, of the liability for approximately $1.2 billion of intercompany debt owed to NiSource Finance Corp. (“NiSource Finance”) by certain subsidiaries in the Columbia Pipeline Group Operations segment, and the novation by NiSource Finance of that $1.2 billion of intercompany debt from the subsidiaries to CEG;

 

   

the contribution by CEG of substantially all of the subsidiaries in the Columbia Pipeline Group Operations segment to Columbia OpCo;

 

   

the receipt by the Partnership of gross proceeds of $800.0 million from the issuance and sale of 40,000,000 common units to the public at an assumed initial offering price of $20.00 per unit in this offering, the midpoint of the price range on the cover of this prospectus;

 

   

the contribution by CEG (which will own all of Columbia OpCo’s limited partner interests) of an approximate 8.4% limited partner interest in Columbia OpCo to us;

 

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Table of Contents
   

in exchange for CEG’s contribution, the issuance by the Partnership to CEG of 6,811,398 common units, all 46,811,398 subordinated units, and all of our incentive distribution rights;

 

   

the use by the Partnership of $45.0 million of the proceeds from the offering to pay the underwriting discount, structuring fee and estimated offering expenses;

 

   

the use by the Partnership of $755.0 million of proceeds from the offering to purchase from Columbia OpCo an additional approximate 6.2% limited partner interest in Columbia OpCo, resulting in the Partnership owning a 14.6% limited partner interest in Columbia OpCo;

 

   

the use by Columbia OpCo of $500.0 million of the proceeds it receives from us to make a distribution to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and the remaining proceeds it receives from us to fund expansion capital expenditures;

 

   

the entry by the Partnership into a $500.0 million revolving credit facility, which is guaranteed by NiSource, HoldCo, CEG, OpCo GP and Columbia OpCo and under which no amounts will be drawn at the closing of this offering. Following HoldCo’s receipt of a rating by Moody’s and S&P, NiSource will be released from its guarantee of our credit facility;

 

   

the entry by Columbia OpCo and its subsidiaries into an intercompany money pool agreement with NiSource Finance with $750.0 million of reserved borrowing capacity, under which no amounts will be drawn at the closing of this offering; and

 

   

the entry by the Partnership and Columbia OpCo into an omnibus agreement and a service agreement with CEG and its affiliates.

The adjustments reflected in the unaudited pro forma combined financial statements are based on currently available information and certain estimates and assumptions. Therefore, actual results may differ from the pro forma adjustments. However, management believes that the estimates and assumptions used provide a reasonable basis for presenting the significant effects of the offering and the related transactions. Management also believes the pro forma adjustments give appropriate effect to the estimates and assumptions and are applied in conformity with accounting principles generally accepted in the United States of America. Refer to Note 2, “Pro Forma Adjustments and Assumptions,” in the Notes to Unaudited Pro Forma Combined Financial Statements for additional information.

These accounting principles are consistent with those used in, and should be read together with, the Predecessor’s historical combined financial statements and related notes, which are included elsewhere in this prospectus.

 

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Columbia Pipeline Partners LP

Unaudited Pro Forma Combined Balance Sheet

 

    As of September 30, 2014  
    Predecessor
Historical
    Contributed/ Non-
Contributed Asset
Adjustments(a)
    Predecessor
Historical As
Adjusted
    Offering Related
Adjustments
    Pro Forma  
    (in millions)  

ASSETS

         

Current Assets

         

Cash and cash equivalents

  $ 0.4      $ (0.1   $ 0.3      $ 800.0 (c)    $ 255.3   
          (500.0 )(d)   
          (45.0 )(e)   

Accounts receivable (less reserve of $0.4)

    121.8        (0.1     121.7        —          121.7   

Accounts receivable—affiliated

    109.3        (7.3     102.0        —          102.0   

Materials and supplies, at average cost

    24.6        —          24.6        —          24.6   

Exchange gas receivable

    56.2        (0.1     56.1        —          56.1   

Regulatory assets

    7.7        (0.1     7.6        —          7.6   

Deferred property taxes

    14.6        —          14.6        —          14.6   

Deferred income taxes

    5.0        0.1        5.1        (5.1 )(b)      —     

Prepayments and other

    18.2        (0.7     17.5        (0.4 )(b)      17.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Current Assets

    357.8        (8.3     349.5        249.5        599.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Investments

         

Unconsolidated affiliates

    434.9        —          434.9        —          434.9   

Other investments

    6.2        (0.6     5.6        —          5.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Investments

    441.1        (0.6     440.5        —          440.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Property, Plant and Equipment

         

Property, plant and equipment

    7,747.1        (37.8     7,709.3        —          7,709.3   

Accumulated depreciation and amortization

    (2,957.0     18.1        (2,938.9     —          (2,938.9
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Property, Plant and Equipment

    4,790.1        (19.7     4,770.4        —          4,770.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Noncurrent Assets

         

Regulatory assets

    128.6        —          128.6        (20.2 )(b)      108.4   

Goodwill

    1,975.5        —          1,975.5        —          1,975.5   

Postretirement and postemployment benefits assets

    105.0        5.3        110.3        —          110.3   

Deferred charges and other

    8.7        (0.1     8.6        1.8 (j)      10.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Noncurrent Assets

    2,217.8        5.2        2,223.0        (18.4     2,204.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

  $ 7,806.8      $ (23.4   $ 7,783.4      $ 231.1      $ 8,014.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying Notes to Unaudited Pro Forma Combined Financial Statements are an integral part of these statements.

 

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    As of September 30, 2014  
    Predecessor
Historical
    Contributed/ Non-
Contributed Asset
Adjustments(a)
    Predecessor
Historical As
Adjusted
    Offering Related
Adjustments
    Pro Forma  
    (in millions)  

LIABILITIES AND PARTNERS’ NET EQUITY

         

Current Liabilities

         

Short-term borrowings—affiliated

  $ 340.7      $ —        $ 340.7      $ (340.7 )(f)    $ —     

Accounts payable

    58.3        (0.1     58.2        —          58.2   

Accounts payable—affiliated

    43.4        5.5        48.9        (14.8 )(f)      35.9   
          1.8 (j)   

Customer deposits

    11.1        (0.2     10.9        —          10.9   

Taxes accrued

    62.9        (0.2     62.7        (2.6 )(b)      60.1   

Exchange gas payable

    58.6        (1.5     57.1        —          57.1   

Deferred revenue

    3.3        0.3        3.6        —          3.6   

Regulatory liabilities

    11.4        —          11.4        —          11.4   

Legal and environmental

    2.2        —          2.2        —          2.2   

Accrued capital expenditures

    74.6        —          74.6        —          74.6   

Other accruals

    63.9        (7.0     56.9        —          56.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Current Liabilities

    730.4        (3.2     727.2        (356.3     370.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Noncurrent Liabilities

         

Long-term debt—affiliated

    1,370.9        —          1,370.9        (859.3 )(f)      511.6   

Deferred income taxes

    1,147.6        (6.6     1,141.0        (1,139.8 )(b)      1.2   

Deferred revenue

    20.9        —          20.9        —          20.9   

Accrued liability for postretirement and postemployment benefits

    28.8        (2.8     26.0        —          26.0   

Regulatory liabilities

    289.0          289.0        (11.0 )(b)      278.0   

Asset retirement obligations

    29.2        (0.4     28.8        —          28.8   

Other noncurrent liabilities

    84.6        (1.0     83.6        (0.2 )(b)      83.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Noncurrent Liabilities

    2,971.0        (10.8     2,960.2        (2,010.3     949.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Liabilities

    3,701.4        (14.0     3,687.4        (2,366.6     1,320.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ Net Equity

         

Net parent investment

    4,122.3        (9.3     4,113.0        1,127.9 (b)      —     
          1,214.8 (f)   
          (6,455.7 )(h)   

Accumulated other comprehensive loss

    (16.9     (0.1     (17.0     17.0 (h)      —     

Common unitholders—public (40,000,000 units issued and outstanding)

    —          —          —          800.0 (c)      650.1   
          (45.0 )(e)   
          (104.9 )(l)   

Common unitholders—sponsor (6,811,398 units issued and outstanding)

    —          —          —          68.7 (i)      50.8   
          (17.9 )(l)   

Subordinated unitholders—sponsor (46,811,398 units issued and outstanding)

    —          —          —          472.2 (i)      349.4   
          (122.8 )(l)   

Non-controlling interest

    —          —          —          5,897.8 (k)      5,643.4   
          (500.0 )(d)   
          245.6 (l)   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Partners’ Net Equity

    4,105.4        (9.4     4,096.0        2,597.7        6,693.7   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Liabilities and Partners’ Net Equity

  $ 7,806.8      $ (23.4   $ 7,783.4      $ 231.1      $ 8,014.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying Notes to Unaudited Pro Forma Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP

Unaudited Pro Forma Combined Statement of Operations

 

    Year Ended December 31, 2013  
    Predecessor
Historical
    Contributed/
Non-Contributed
Asset
Adjustments(a)
    Predecessor
Historical As
Adjusted
    Offering
Related
Adjustments
    Pro Forma  
    (in millions)  

Operating Revenues

         

Transportation revenues

  $ 850.9      $ (2.5   $ 848.4      $ —        $ 848.4   

Transportation revenues—affiliated

    94.3        (1.5     92.8        —          92.8   

Storage revenues

    142.8        —          142.8        —          142.8   

Storage revenues—affiliated

    53.6        —          53.6        —          53.6   

Other revenues

    37.8        1.3        39.1        —          39.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Revenues

    1,179.4        (2.7     1,176.7        —          1,176.7   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Expenses

         

Operation and maintenance

    507.1        (25.7     481.4        —          481.4   

Operation and maintenance—affiliated

    118.1        24.4        142.5        —          142.5   

Depreciation and amortization

    106.9        (0.8     106.1        —          106.1   

Gain on sale of assets

    (18.6     —          (18.6     —          (18.6

Property and other taxes

    62.2        (0.3     61.9        —          61.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

    775.7        (2.4     773.3        —          773.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

    35.9        (0.1     35.8        —          35.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

    439.6        (0.4     439.2        —          439.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

         

Interest expense—affiliated

    (37.9     —          (37.9     37.9 (f)      (1.8
          (1.8 )(j)   

Other, net

    17.6        —          17.6        5.0 (f)      22.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Deductions, net

    (20.3     —          (20.3     41.1        20.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before Income Taxes

    419.3        (0.4     418.9        41.1        460.0   

Income Taxes

    152.4        (0.2     152.2        (152.0 )(b)      0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

    266.9        (0.2     266.7        193.1        459.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Non-Controlling Interests

    —          —          —          (392.7 )(g)      (392.7
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income Attributable to Columbia Pipeline Partners LP

  $ 266.9      $ (0.2   $ 266.7      $ (199.6   $ 67.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Limited partner interests in net income:

         

Common units

          $ 33.6   

Subordinated units

          $ 33.5   

Net income per limited partner unit (basic and diluted):

         

Common units

          $ 0.72   

Subordinated units

          $ 0.72   

Weighted average number of limited partner units outstanding (basic and diluted):

         

Common units

            46.8   

Subordinated units

            46.8   

The accompanying Notes to Unaudited Pro Forma Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP

Unaudited Pro Forma Combined Statement of Operations

 

    Nine Months Ended September 30, 2014  
    Predecessor
Historical
    Contributed/
Non-Contributed
Asset
Adjustments(a)
    Predecessor
Historical As
Adjusted
    Offering
Related
Adjustments
    Pro Forma  
    (in millions)  

Operating Revenues

         

Transportation revenues

  $ 743.5      $ (1.4   $ 742.1      $ —        $ 742.1   

Transportation revenues—affiliated

    66.3        (0.7     65.6        —          65.6   

Storage revenues

    108.2        —          108.2        —          108.2   

Storage revenues—affiliated

    40.1        —          40.1        —          40.1   

Other revenues

    48.4        1.0        49.4        —          49.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Revenues

    1,006.5        (1.1     1,005.4        —          1,005.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Expenses

         

Operation and maintenance

    477.1        (22.5     454.6        —          454.6   

Operation and maintenance—affiliated

    89.6        21.5        111.1        —          111.1   

Depreciation and amortization

    87.7        (0.5     87.2        —          87.2   

Gain on sale of assets

    (20.8     —          (20.8     —          (20.8

Property and other taxes

    50.3        (0.2     50.1        —          50.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

    683.9        (1.7     682.2        —          682.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

    32.9        —          32.9        —          32.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

    355.5        0.6        356.1        —          356.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

         

Interest expense—affiliated

    (39.1     —          (39.1     34.8 (f)      (5.7
          (1.4 )(j)   

Other, net

    8.0        —          8.0        —          8.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Deductions, net

    (31.1     —          (31.1     33.4        2.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before Income Taxes

    324.4        0.6        325.0        33.4        358.4   

Income Taxes

    119.7        0.3        120.0        (119.8 )(b)      0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

    204.7        0.3        205.0        153.2        358.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Non-Controlling Interests

    —          —          —          (305.9 )(g)      (305.9
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income Attributable to Columbia Pipeline Partners LP

  $ 204.7      $ 0.3      $ 205.0      $ (152.7   $ 52.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Limited partner interests in net income:

         

Common units

          $ 26.2   

Subordinated units

          $ 26.1   

Net income per limited partner unit (basic and diluted):

         

Common units

          $ 0.56   

Subordinated units

          $ 0.56   

Weighted average number of limited partner units outstanding (basic and diluted):

         

Common units

            46.8   

Subordinated units

            46.8   

The accompanying Notes to Unaudited Pro Forma Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP

Notes to Unaudited Pro Forma Combined Financial Statements

 

1. Basis of Presentation

The historical financial information for the year ended December 31, 2013 is derived from and should be read in conjunction with the audited historical combined financial statements of the Predecessor appearing elsewhere in this prospectus, and the assumptions outlined in Note 2 below. The historical financial information for the nine months ended September 30, 2014 and balance sheet information at September 30, 2014 is derived from and should be read in conjunction with the unaudited historical financial statements of the Predecessor. In each case, the historical financial information reflects 100% of the Predecessor’s operations. However, the Partnership will only own a 14.6% limited partner interest in Columbia OpCo.

The pro forma adjustments have been prepared as if certain transactions to be completed in conjunction with the offering had taken place on January 1, 2013 in the case of the pro forma statements of operations for the year ended December 31, 2013 and the nine months ended September 30, 2014, or on September 30, 2014 in the case of the pro forma balance sheet. These transactions and adjustments are described in Note 2 to these unaudited pro forma combined financial statements.

Also, upon completion of this offering, we anticipate incurring incremental general and administrative expense of approximately $5.0 million per year as a result of being a publicly traded limited partnership, including expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, and registrar and transfer agent fees. The unaudited pro forma combined financial statements do not reflect these additional public company costs.

 

2. Pro Forma Adjustments and Assumptions

 

(a) Reflects the removal of amounts related to Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company that were included in the Predecessor but are not being contributed to the Partnership, as well as the inclusion of CNS Microwave, Inc., which was not part of the Predecessor.

 

(b) Reflects the elimination of all historical current and deferred income taxes other than Tennessee state income taxes that will continue to be borne by the Partnership post-offering, as well as associated regulatory assets and liabilities.

 

(c) Reflects the assumed gross proceeds to the Partnership of $800.0 million from the issuance and sale of 40,000,000 million common units at an assumed initial public offering price of $20.00 per unit.

 

(d) Reflects the distribution of $500.0 million to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo.

 

(e) Reflects the payment of the underwriting discount of $36.0 million, a structuring fee of $4.0 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc. and other offering expenses of $5.0 million for a total of $45.0 million, which will be offset against the public common units.

 

(f) Reflects the assumption of $340.7 million of short-term borrowings —affiliated and $859.3 million of long-term debt—affiliated for a total of $1.2 billion of debt by an affiliate of NiSource as of September 30, 2014, as well as assumption of associated accrued interest, interest expense and the reclassification of $5.0 million in AFUDC debt to AFUDC equity in Other, net for the year ended December 31, 2013.

 

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(g) Income attributable to non-controlling interests of $305.9 million for the nine months ended September 30, 2014 and $392.7 million for year ended December 31, 2013, which represents CEG’s 85.4% limited partner interest in Columbia OpCo’s net income.

 

     Nine Months
Ended September 30,
2014
    Year Ended
December 31,
2013
 
     (in millions)  

Pro forma predecessor net income

   $ 358.2      $ 459.8   

Non-controlling interest %

     85.4     85.4
  

 

 

   

 

 

 

Pro forma non-controlling interest in net income

   $ 305.9      $ 392.7   
  

 

 

   

 

 

 

 

(h) Reflects the elimination of CEG’s net investment in the Predecessor and its reclassification to the Partnership’s capital accounts calculated as follows:

 

     September 30,
2014
 
     (in millions)  

Predecessor historical as adjusted net parent investment

   $ 4,113.0   

Equity impact of elimination of all historical current and deferred income taxes other than Tennessee state income taxes (see note (b))

     1,127.9   

Equity impact of the assumption of debt (see note (f))

     1,214.8   
  

 

 

 
   $ 6,455.7   

Accumulated other comprehensive loss

     (17.0
  

 

 

 

CEG’s net investment in the Predecessor prior to the formation transactions

   $ 6,438.7   
  

 

 

 

 

(i) Reflects the CEG contribution of an 8.4% limited partner interest in Columbia OpCo to the Partnership calculated as follows:

 

     September 30,
2014
 
     ($ in millions)  

CEG’s net investment in the Predecessor prior to the formation transactions (see note (h))

   $ 6,438.7   

Percentage of limited partner interest in Columbia OpCo contributed

     8.4
  

 

 

 

Book value of the limited partner interest in Columbia OpCo contributed by CEG to the Partnership

   $ 540.9 (1) 
  

 

 

 

 

  (1) 

Amount is allocated between common and subordinated CEG equity accounts based on the percentage of units received as part of this contribution.

 

(j) Reflects the payment of origination fees by an affiliate of NiSource of $1.8 million and $1.5 million in commitment fees which are to be incurred in connection with our new revolving credit facility. The origination fees are expected to be amortized over the life of the facility at a rate of approximately $0.3 million per year. The amortization of the origination fees is $0.2 million for the nine months ended September 30, 2014 and $0.3 million for the year ended December 31, 2013.

 

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(k) Reflects 85.4% noncontrolling interest held by CEG in Columbia OpCo calculated as follows:

 

     September 30,
2014
 
     ($ in millions)  

CEG’s net investment in the Predecessor prior to the formation transactions

   $ 6,438.7   

Gross proceeds from the initial public offering (see note (c))

     800.0   

Underwriters discount, fees and other offering expenses (see note (e))

     (45.0
  

 

 

 

Net equity before noncontrolling interest

     7,193.7   

Noncontrolling interest held by CEG in Columbia OpCo

     85.4
  

 

 

 

Noncontrolling interest in OpCo after the initial public offering

   $ 6,143.4   

Less: adjustment (l) below

     (245.6
  

 

 

 

Noncontrolling interest pro forma adjustment

   $ 5,897.8   

 

(l) Represents the purchase of an additional 6.2% limited partner interest in Columbia OpCo, recorded at the historical carrying value of Columbia OpCo’s net assets after giving effect to the $755.0 million equity contribution calculated as follows:

 

     September 30,
2014
 
     ($ in millions)  

CEG’s net investment in the Predecessor prior to the formation transactions (see above)

   $ 6,438.7   

Gross proceeds from the initial public offering (see note (c))

     800.0   

Underwriters discount, fees and other offering expenses (see note (e))

     (45.0
  

 

 

 

Net equity after receipt of proceeds from the offering

     7,193.7   
  

 

 

 

Limited partner interest % subsequent to the purchase of additional interest in Columbia OpCo

     14.6
  

 

 

 

Book value of controlling interest in Columbia OpCo after the purchase of additional interest in Columbia OpCo

   $ 1,050.3   
  

 

 

 

Less: Book value of the limited partner interest in Columbia OpCo contributed by CEG to the Partnership (see (i))

   $ 540.9   
  

 

 

 

Book value of the limited partner interest in Columbia OpCo purchased using proceeds from the offering

   $ 509.4   
  

 

 

 

Less: Consideration paid by us for the additional limited partner interest in Columbia OpCo

   $ 755.0   
  

 

 

 

Excess of the consideration paid by us to purchase our additional limited partner interest in Columbia OpCo with the net proceeds from this offering over the historical carrying value of the additional interest acquired in Columbia OpCo’s net assets(2)

   $ (245.6
  

 

 

 

 

  (2) 

This amount is allocated to the limited partner equity accounts based on their respective ownership percentages of the Partnership subsequent to the purchase of the additional interest in Columbia OpCo. Additionally, this amount increases noncontrolling interest by the same amount it decreases controlling equity because the Partnership is paying more than book value for the additional 6.2% limited partner interest.

 

3. Pro Forma Net Income per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the provisions of the limited partnership agreement, to the common and subordinated unitholders by the number of common and subordinated units expected to be outstanding at the

 

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closing of the offering. For purposes of this calculation, we assumed that (1) pro forma distributions were equal to pro forma earnings, (2) the number of units outstanding was 46,811,398 common and 46,811,398 subordinated, and (3) all units were assumed to have been outstanding since the beginning of the periods presented. During the year ended December 31, 2013 and nine months ended September 30, 2014, $0.72 per unit and $0.56 per unit, respectively, would have been distributed to all common and subordinated unitholders. Although the $0.72 and $0.56 reflect quarterly distributions in excess of the minimum quarterly distribution amount of $0.1675 per unit, they are below the first target distribution level of $0.192625 per unit. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the holder of the incentive distribution rights (the “IDR holder”) is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the IDR holder than to the holders of common and subordinated units. The pro forma net income per unit calculations reflect the fact that no incentive distributions were made to the IDR holder.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of CPP GP LLC, and Partners of Columbia Pipeline Partners LP

Houston, Texas

We have audited the accompanying consolidated balance sheet of Columbia Pipeline Partners LP (the “Company”) at June 30, 2014. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated balance sheet presents fairly, in all material respects, the financial position of Columbia Pipeline Partners LP at June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Chicago, Illinois

September 26, 2014

 

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Columbia Pipeline Partners LP

Balance Sheet

 

     As of June 30,
2014
 

ASSETS

  
  

 

 

 

Total Assets

   $ —     
  

 

 

 

PARTNERS’ EQUITY

  

Partners’ Equity

  

Limited partners’ equity

   $ 1,960   

General partners’ equity

     40   
  

 

 

 

Less note receivable from NiSource Inc.

     (2,000
  

 

 

 

Total Liabilities and Partners’ Equity

   $ —     
  

 

 

 

The accompanying Note to the Balance Sheet is an integral part of this statement.

 

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Table of Contents

Columbia Pipeline Partners LP Note to the Balance Sheet

 

1. Nature of Operations

Columbia Pipeline Partners LP (the “Partnership”) is a Delaware limited partnership formed on December 5, 2007 to own, operate and develop a portfolio of pipelines, storage and related assets. The Partnership’s mutual assets will consist of a 14.6% limited partner interest in CPG OpCo LP, through which the Partnership’s business and operations will be conducted.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests, to Columbia Energy Group (“CEG”).

CPP GP LLC, the general partner of the Partnership and a wholly owned subsidiary of CEG, committed to contribute $40 in the form of a note receivable to the Partnership on December 5, 2007. At the completion of the offering, the 2% general partner interest will be converted to a non-economic general partner interest. CEG, the organizational limited partner of the Partnership and a wholly owned subsidiary of NiSource Inc., committed to contribute $1,960 in the form of a note receivable to the Partnership on December 5, 2007. There have been no other transactions involving the Partnership.

 

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Table of Contents

Columbia Pipeline Partners LP

Balance Sheet (Unaudited)

 

     As of September 30,
2014
 

ASSETS

  
  

 

 

 

Total Assets

   $ —     
  

 

 

 

PARTNERS’ EQUITY

  

Partners’ Equity

  

Limited partners’ equity

   $ 1,960   

General partners’ equity

     40   
  

 

 

 

Less note receivable from NiSource Inc.

     (2,000
  

 

 

 

Total Liabilities and Partners’ Equity

   $ —     
  

 

 

 

The accompanying Note to the Balance Sheet (Unaudited) is an integral part of this statement.

 

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Table of Contents

Columbia Pipeline Partners LP Note to the Balance Sheet (Unaudited)

 

1. Nature of Operations

Columbia Pipeline Partners LP (the “Partnership”) is a Delaware limited partnership formed on December 5, 2007 to own, operate and develop a portfolio of pipelines, storage and related assets. The Partnership’s mutual assets will consist of a 14.6% limited partner interest in CPG OpCo LP, through which the Partnership’s business and operations will be conducted.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests, to Columbia Energy Group (“CEG”).

CPP GP LLC, the general partner of the Partnership and a wholly owned subsidiary of CEG, committed to contribute $40 in the form of a note receivable to the Partnership on December 5, 2007. At the completion of the offering, the 2% general partner interest will be converted to a non-economic general partner interest. CEG, the organizational limited partner of the Partnership and a wholly owned subsidiary of NiSource Inc., committed to contribute $1,960 in the form of a note receivable to the Partnership on December 5, 2007. There have been no other transactions involving the Partnership.

 

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Table of Contents

Columbia Pipeline Partners LP Predecessor

Condensed Combined Balance Sheets (Unaudited)

 

     Supplemental Pro
Forma

September 30,
2014
    September 30,
2014
    December 31,
2013
 
     (in millions)  

ASSETS

      

Current Assets

      

Cash and cash equivalents

   $ 0.4      $ 0.4      $ 0.3   

Accounts receivable (less reserve of $0.4, $0.4 and $0.1, respectively)

     121.8        121.8        128.0   

Accounts receivable—affiliated

     109.3        109.3        94.4   

Materials and supplies, at average cost

     24.6        24.6        24.8   

Exchange gas receivable

     56.2        56.2        49.2   

Regulatory assets

     7.7        7.7        12.3   

Deferred property taxes

     14.6        14.6        46.8   

Deferred income taxes

     5.0        5.0        9.7   

Prepayments and other

     18.2        18.2        12.6   
  

 

 

   

 

 

   

 

 

 

Total Current Assets

     357.8        357.8        378.1   
  

 

 

   

 

 

   

 

 

 

Investments

      

Unconsolidated affiliates

     434.9        434.9        364.5   

Other investments

     6.2        6.2        12.3   
  

 

 

   

 

 

   

 

 

 

Total Investments

     441.1        441.1        376.8   
  

 

 

   

 

 

   

 

 

 

Property, Plant and Equipment

      

Property, plant and equipment

     7,747.1        7,747.1        7,191.4   

Accumulated depreciation and amortization

     (2,957.0     (2,957.0     (2,888.0
  

 

 

   

 

 

   

 

 

 

Net Property, Plant and Equipment

     4,790.1        4,790.1        4,303.4   
  

 

 

   

 

 

   

 

 

 

Other Noncurrent Assets

      

Regulatory assets

     128.6        128.6        130.3   

Goodwill

     1,975.5        1,975.5        1,975.5   

Postretirement and post employment benefits assets

     105.0        105.0        93.1   

Deferred charges and other

     8.7        8.7        4.6   
  

 

 

   

 

 

   

 

 

 

Total Other Noncurrent Assets

     2,217.8        2,217.8        2,203.5   
  

 

 

   

 

 

   

 

 

 

Total Assets

   $ 7,806.8      $ 7,806.8      $ 7,261.8   
  

 

 

   

 

 

   

 

 

 

LIABILITIES AND PARENT NET EQUITY

      

Current Liabilities

      

Short-term borrowings—affiliated

   $ 340.7      $ 340.7      $ 719.6   

Accounts payable

     58.3        58.3        71.9   

Accounts payable—affiliated

     43.4        43.4        41.3   

Distribution payable to parent

     500.0        —          —     

Customer deposits

     11.1        11.1        11.5   

Taxes accrued

     62.9        62.9        96.0   

Exchange gas payable

     58.6        58.6        48.1   

Deferred revenue

     3.3        3.3        14.9   

Regulatory liabilities

     11.4        11.4        0.8   

Legal and environmental

     2.2        2.2        8.4   

Accrued capital expenditures

     74.6        74.6        26.7   

Other accruals

     63.9        63.9        58.1   
  

 

 

   

 

 

   

 

 

 

Total Current Liabilities

     1,230.4        730.4        1,097.3   
  

 

 

   

 

 

   

 

 

 

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Table of Contents
     Supplemental  Pro
Forma

September 30, 2014
    September 30,
2014
    December 31,
2013
 
     (in millions)  

Noncurrent Liabilities

      

Long-term debt—affiliated

     1,370.9        1,370.9        819.8   

Deferred income taxes

     1,147.6        1,147.6        1,077.0   

Deferred revenue

     20.9        20.9        17.1   

Accrued liability for postretirement and postemployment benefits

     28.8        28.8        32.7   

Regulatory liabilities

     289.0        289.0        282.3   

Asset retirement obligations

     29.2        29.2        26.3   

Other noncurrent liabilities

     84.6        84.6        9.4   
  

 

 

   

 

 

   

 

 

 

Total Noncurrent Liabilities

     2,971.0        2,971.0        2,264.6   
  

 

 

   

 

 

   

 

 

 

Total Liabilities

     4,201.4        3,701.4        3,361.9   
  

 

 

   

 

 

   

 

 

 

Commitments and Contingencies (Refer to Note 12)

      

Parent Net Equity

      

Net parent investment

     3,622.3        4,122.3        3,917.6   

Accumulated other comprehensive loss

     (16.9     (16.9     (17.7
  

 

 

   

 

 

   

 

 

 

Total Parent Net Equity

     3,605.4        4,105.4        3,899.9   
  

 

 

   

 

 

   

 

 

 

Total Liabilities and Parent Net Equity

   $ 7,806.8      $ 7,806.8      $ 7,261.8   
  

 

 

   

 

 

   

 

 

 

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Condensed Combined Statements of Operations (Unaudited)

 

     Nine Months Ended September 30,  
             2014                     2013          
     (in millions)  

Operating Revenues

    

Transportation revenues

   $ 743.5      $ 621.4   

Transportation revenues—affiliated

     66.3        65.3   

Storage revenues

     108.2        107.4   

Storage revenues—affiliated

     40.1        40.3   

Other revenues

     48.4        23.2   
  

 

 

   

 

 

 

Total Operating Revenues

     1,006.5        857.6   
  

 

 

   

 

 

 

Operating Expenses

    

Operation and maintenance

     477.1        366.7   

Operation and maintenance—affiliated

     89.6        82.4   

Depreciation and amortization

     87.7        78.9   

Gain on sale of assets

     (20.8     (11.3

Property and other taxes

     50.3        46.6   
  

 

 

   

 

 

 

Total Operating Expenses

     683.9        563.3   
  

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

     32.9        25.6   
  

 

 

   

 

 

 

Operating Income

     355.5        319.9   
  

 

 

   

 

 

 

Other Income (Deductions)

    

Interest expense—affiliated

     (39.1     (27.6

Other, net

     8.0        15.3   
  

 

 

   

 

 

 

Total Other Deductions, net

     (31.1     (12.3
  

 

 

   

 

 

 

Income before Income Taxes

     324.4        307.6   

Income Taxes

     119.7        112.4   
  

 

 

   

 

 

 

Net Income

   $ 204.7      $ 195.2   
  

 

 

   

 

 

 

Unaudited pro forma basic earnings per common unit (Refer to Note 1C)

   $ 0.50     

Unaudited pro forma diluted earnings per common unit (Refer to Note 1C)

   $ 0.50     
  

 

 

   

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Table of Contents

Columbia Pipeline Partners LP Predecessor Condensed Combined Statements of Comprehensive Income (Unaudited)

 

     Nine Months Ended September 30,  
             2014                      2013          
     (in millions, net of taxes)  

Net Income

   $ 204.7       $ 195.2   

Other comprehensive income (loss):

     

Net unrealized gain on cash flow hedges(1)

     0.8         0.8   

Unrecognized pension and OPEB costs(2)

     —           (0.2
  

 

 

    

 

 

 

Total other comprehensive income

     0.8         0.6   
  

 

 

    

 

 

 

Total Comprehensive Income

   $ 205.5       $ 195.8   
  

 

 

    

 

 

 

 

(1) 

Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.5 million tax expense in 2014 and 2013.

(2)

Unrecognized pension benefit and OPEB costs, net of $0.1 million tax benefit in 2013.

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Condensed Combined Statements of Cash Flows (Unaudited)

 

     Nine Months Ended September 30,  
         2014             2013      
     (in millions)  

Operating Activities

    

Net income

   $ 204.7     $ 195.2  

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities

    

Depreciation and amortization

     87.7       78.9  

Deferred income taxes and investment tax credits

     69.5       151.7  

Deferred revenue

     2.3       1.7  

Stock compensation expense and 401(k) profit sharing contribution

     4.4       1.3  

Gain on sale of assets

     (20.8     (11.3

Income from unconsolidated affiliates

     (32.9     (25.6

AFUDC equity

     (8.2     (4.6

Distributions of earnings received from equity investees

     27.6       19.0  

Changes in Assets and Liabilities:

    

Accounts receivable

     2.3        15.6  

Accounts receivable—affiliated

     19.6       12.4  

Accounts payable

     (0.4 )     2.1  

Accounts payable—affiliated

     2.1        3.6   

Customer deposits

     75.2       0.1  

Taxes accrued

     (33.0     (89.6

Exchange gas receivable/payable

     3.5       1.3  

Other accruals

     (0.1 )     (0.5 )

Prepayments and other current assets

     26.8       48.9  

Regulatory assets/liabilities

     35.3       (35.5

Postretirement and postemployment benefits

     (15.9     (36.6

Deferred charges and other noncurrent assets

     (3.9     5.5  

Other noncurrent liabilities

     0.8        (17.1
  

 

 

   

 

 

 

Net Cash Flows from Operating Activities

     446.6       316.5  
  

 

 

   

 

 

 

Investing Activities

    

Capital expenditures

     (527.4     (457.1

Insurance recoveries

     6.8       6.4  

Changes in short-term lendings—affiliated

     (34.6     (8.6

Proceeds from disposition of assets

     5.9       15.3  

Contributions to equity investees

     (63.8     (77.0

Other investing activities

     (5.5     (6.6
  

 

 

   

 

 

 

Net Cash Flows used for Investing Activities

     (618.6     (527.6
  

 

 

   

 

 

 

Financing Activities

    

Changes in short-term borrowings—affiliated

     (378.9     315.6  

Issuance of long-term debt—affiliated

     551.0       —    

Dividends to parent

     —         (105.0
  

 

 

   

 

 

 

Net Cash Flows from Financing Activities

     172.1       210.6  
  

 

 

   

 

 

 

Change in cash and cash equivalents

     0.1        (0.5

Cash and cash equivalents at beginning of period

     0.3       0.6  
  

 

 

   

 

 

 

Cash and Cash Equivalents at End of Period

   $ 0.4     $ 0.1  
  

 

 

   

 

 

 

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Table of Contents

Columbia Pipeline Partners LP Predecessor Condensed Combined Statements of Parent Net Equity (Unaudited)

 

     Net Parent
Investment
    Accumulated
Other
Comprehensive
Income/(Loss)
    Total  
     (in millions)  

Balance January 1, 2014

   $ 3,917.6      $ (17.7   $ 3,899.9   
  

 

 

   

 

 

   

 

 

 

Net Income

     204.7       —         204.7  

Other comprehensive income, net of tax

     —         0.8       0.8  
  

 

 

   

 

 

   

 

 

 

Balance September 30, 2014

   $ 4,122.3     $ (16.9 )   $ 4,105.4  
  

 

 

   

 

 

   

 

 

 

Balance January 1, 2013

   $ 3,758.3     $ (18.8 )   $ 3,739.5  
  

 

 

   

 

 

   

 

 

 

Net Income

     195.2       —         195.2  

Dividends to parent

     (105.0 )     —         (105.0

Other comprehensive income, net of tax

     —         0.6       0.6  
  

 

 

   

 

 

   

 

 

 

Balance September 30, 2013

   $ 3,848.5     $ (18.2 )   $ 3,830.3  
  

 

 

   

 

 

   

 

 

 

The accompanying Notes to Condensed Combined Financial Statements (unaudited) are an integral part of these statements.

 

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Table of Contents

Columbia Pipeline Partners LP Predecessor

Notes to Condensed Combined Financial Statements (Unaudited)

 

1. Nature of Operations and Summary of Significant Accounting Policies

A. Company Structure and Basis of Presentation. The accompanying Condensed Combined Financial Statements (unaudited) of Columbia Pipeline Partners LP Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering (the “offering”) of common units representing limited partner interests in Columbia Pipeline Partners LP (the “Partnership”). Formed in Delaware on December 5, 2007, the Partnership is a subsidiary of NiSource Inc. (“NiSource”). NiSource is a Delaware corporation and holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the midwest to New England. The Predecessor is comprised of NiSource’s Columbia Pipeline Group Operations reportable segment which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource.

As part of the offering, NiSource will contribute substantially all of the Predecessor’s assets and operations to CPG OpCo LP (“Columbia OpCo”), a Delaware limited partnership formed by Columbia Energy Group (“CEG”), a wholly owned subsidiary of NiSource, and CPG OpCo GP LLC (“OpCo GP”), a wholly owned subsidiary of the Partnership. The Partnership will own a 14.6% limited partner interest in Columbia OpCo and CEG will retain the remaining 85.4% limited partner interest. CPP GP LLC (“MLP GP”), a wholly owned subsidiary of CEG, will serve as the general partner for the Partnership. OpCo GP will serve as the general partner for Columbia OpCo. Columbia Pipeline Group Services Company will provide services to the Partnership pursuant to an omnibus agreement. MLP GP, the Partnership, Columbia OpCo and OpCo GP have all adopted December 31 fiscal year ends.

The Predecessor is engaged in regulated gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under a tariff and at rates subject to FERC approval.

The Condensed Combined Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although the Predecessor believes that the disclosures made are adequate to make the information not misleading. These financial statements should be read in conjunction with the Predecessor’s combined financial statements for the year ended December 31, 2013. These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the Predecessor’s results of operations and financial position. Amounts reported in the Condensed Combined Statement of Operations (unaudited) are not necessarily indicative of amounts expected for the respective annual periods.

The Predecessor’s accompanying Condensed Combined Financial Statements (unaudited) have been prepared in accordance with accounting principles generally accepted in the United States on the basis of NiSource’s historical ownership of the Predecessor’s assets and its operations. These financial statements include the Predecessor’s accounts which include the subsidiaries, Columbia Gas Transmission, LLC, Columbia Gulf Transmission, LLC, Columbia Midstream Group, LLC, Columbia Energy Ventures, LLC (“CEVCO”), Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company. As the financial statements do not include a common parent company, the financial statements are presented as combined. Also included in the combined financial statements are equity method investments Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C., and Pennant Midstream, LLC. All intercompany transactions and balances have been eliminated. A direct ownership relationship does not exist among the entities

 

F-23


Table of Contents

comprising the Predecessor; therefore the net investment in the Predecessor is shown as Parent Net Equity in lieu of owner’s equity in the Condensed Combined Financial Statements (unaudited).

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses (which comprises substantially all of Columbia Pipeline Partners LP Predecessor) through a distribution to NiSource stockholders of all of the outstanding common stock of Columbia Pipeline Group, Inc. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions.

Subsequent events have been evaluated through November 10, 2014, the date these financial statements were available to be issued. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the financial statements.

B. Natural Gas and Oil Properties. The Predecessor includes the subsidiary CEVCO, which owns the mineral rights to over 450,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $34.1 million and $14.2 million for the nine months ended September 30, 2014 and 2013, respectively. As part of a contribution to Hilcorp, CEVCO participates as a working interest partner in the development by a partnership of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method.

CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest with Hilcorp. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors.

The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2014 and 2013:

 

     2014     2013  
     (in millions)  

Beginning Balance

   $ 1.9      $ 3.0   

Additions pending the determination of proved reserves

     11.2        4.0   

Reclassifications of proved properties

     (0.5     (4.0
  

 

 

   

 

 

 

Ending Balance

   $ 12.6      $ 3.0   
  

 

 

   

 

 

 

As of September 30, 2014, there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to two projects initiated in the first nine months of 2013.

C. Supplemental Pro Forma Information. Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, the Partnership intends to distribute approximately $500.0 million in cash to parent. This distribution will be paid with offering proceeds. The supplemental pro forma balance sheet as of September 30, 2014 gives pro forma effect to this assumed distribution as though it had been declared and was payable as of that date. The unaudited pro forma basic and diluted earnings per common unit for the nine months ended September 30, 2014 assumed 30,316,398 common units were outstanding in the period. The 30,316,398 common units consists of 6,811,398 units issued to CEG plus an additional 23,505,000 units, which is the number of common units we would have been required to issue to fund the $500.0 million distribution. For the nine months ended September 30, 2014, pro forma basic and diluted net income per common unit would have been $0.50.

 

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Table of Contents
2. Recent Accounting Pronouncements

In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that represents a strategic shift that has or will have a major impact on its operations and financial results is a discontinued operation. The Predecessor is required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. The Predecessor is currently evaluating what impact, if any, adoption of ASU 2014-08 will have on its Condensed Combined Financial Statements and Notes to Condensed Combined Financial Statements.

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Predecessor is required to adopt ASU 2014-09 for periods beginning after December 15, 2016, including interim periods, and the standard is to be applied retrospectively. Early adoption is not permitted. The Predecessor is currently evaluating the impact the adoption of ASU 2014-09 will have on our Condensed Combined Financial Statements and Notes to Condensed Combined Financial Statements.

 

3. Transactions with Affiliates

In the normal course of business, the Predecessor engages in transactions with subsidiaries of NiSource. Transactions with affiliates are summarized in the tables below:

Statement of Operations.

 

    

Nine Months Ended September 30,

 
    

         2014         

              2013            
     (in millions)  

Transportation revenues

   $ 66.3       $ 65.3   

Storage revenues

     40.1         40.3   

Other revenues

     0.2         0.2   

Operation and maintenance expense

     89.6         82.4   

Interest expense

     39.1         27.6   

Interest income

     0.3         0.4   

Balance Sheet.

 

     September 30,
2014
     December 31,
2013
 
     (in millions)  

Accounts receivable

   $ 109.3       $ 94.4   

Short-term borrowings

     340.7         719.6   

Accounts payable

     43.4         41.3   

Long-term debt

     1,370.9         819.8   

Transportation, Storage and Other Revenues. The Predecessor provides natural gas transportation, storage and other services to subsidiaries of NiSource.

Operation and Maintenance Expense. The Predecessor receives executive, financial, legal, information technology and other administrative and general services from an affiliate, NiSource Corporate Services. Expenses incurred as a result of these services consist of employee compensation and benefits, outside services and other expenses. The Predecessor is charged directly or allocated using various allocation methodologies

 

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based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable; however, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity.

Interest Expense and Income. The Predecessor was charged interest for long-term debt of $42.5 million for the nine months ended September 30, 2014 and $30.2 million for the nine months ended September 30, 2013, offset by associated AFUDC of $6.0 million for the nine months ended September 30, 2014 and $5.5 million for the nine months ended September 30, 2013.

NiSource Corporate Services administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. The subsidiaries of the Predecessor participated in the money pool for all of the periods presented in the financial statements. The cash accounts maintained by subsidiaries of the Predecessor are swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and the Predecessor. The amount of interest expense and income for short-term borrowings is determined by the net position of each subsidiary of the Predecessor in the money pool. The money pool weighted-average interest rate at September 30, 2014 and 2013 was 0.68% and 0.93%, respectively. The interest expense for short-term borrowings charged for the nine months ended September 30, 2014 and 2013 was $2.6 million and $2.9 million, respectively.

Accounts Receivable. The Predecessor includes in accounts receivable amounts due from the money pool at September 30, 2014 and December 31, 2013 of $97.9 million and $63.4 million, respectively, for subsidiaries in a net deposit position. Also included in the balance at September 30, 2014 and December 31, 2013 are amounts due from subsidiaries of NiSource for transportation and storage services of $11.4 million and $31.0 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Condensed Combined Statements of Cash Flows (unaudited). All other affiliated receivables are included as Operating Activities.

Short-term Borrowings. The balance at September 30, 2014 and December 31, 2013 includes all subsidiaries of the Predecessor in a net borrower position. Net cash flows related to short-term borrowings are included as Financing Activities on the Condensed Combined Statements of Cash Flows (unaudited).

Accounts Payable. The affiliated accounts payable primarily includes amounts due for services received from NiSource Corporate Services and interest payable to NiSource Finance.

Long-term Debt. The Predecessor’s long-term financing requirements are satisfied through borrowings from NiSource Finance. Details of the long-term debt balance are summarized in the table below:

 

Origination Date

   Interest Rate     Maturity Date      September 30,
2014
     December 31,
2013
 
                  (in millions)  

November 28, 2005

     5.41     November 30, 2015       $ 115.9       $ 115.9   

November 28, 2005

     5.45     November 28, 2016         45.3         45.3   

November 28, 2005

     5.92     November 28, 2025         133.5         133.5   

November 28, 2012

     4.63     November 28, 2032         45.0         45.0   

November 28, 2012

     4.94     November 30, 2037         95.0         95.0   

December 19, 2012

     5.16     December 21, 2037         55.0         55.0   

November 28, 2012

     5.26     November 28, 2042         170.0         170.0   

December 19, 2012

     5.49     December 18, 2042         95.0         95.0   

December 9, 2013(1)

     4.75     December 31, 2016         616.2         65.1   
       

 

 

    

 

 

 

Total Long-term Debt

        $ 1,370.9       $ 819.8   
       

 

 

    

 

 

 

 

(1) 

The Predecessor may borrow at any time from the origination date to maturity date not to exceed $2.6 billion. The note carries variable interest rate of prime plus 150 basis points. All funds borrowed on the note are due December 31, 2016.

 

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Dividends. The Predecessor paid no dividends to the parent for the nine months ended September 30, 2014 and paid $105.0 million in dividends to the parent for the nine months ended September 30, 2013. There are no restrictions on the payment of dividends to the parent.

 

4. Gain on Sale of Assets

During the nine months ended September 30, 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million.

The Predecessor recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. Gains on conveyances of $20.8 million were recorded in earnings for the nine months ended September 30, 2014. As of September 30, 2014 and December 31, 2013, deferred gains of approximately $21.0 million and $30.0 million, respectively, were deferred pending performance of future obligations and recorded in deferred revenue on the Condensed Combined Balance Sheets (unaudited).

 

5. Goodwill

The Predecessor tests its goodwill for impairment annually as of May 1 unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, which is consistent with the level of discrete financial information reviewed by the Predecessor’s management. Columbia Transmission Operations, which is included in the Predecessor, has been determined to be a reporting unit. The Predecessor’s goodwill assets at September 30, 2014 and December 31, 2013 were approximately $2.0 billion pertaining to the acquisition of Columbia Energy Group on November 1, 2000.

The Predecessor completed a quantitative (“step 1”) fair value measurement of its reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded its carrying value, indicating that no impairment existed.

Accounting Standards Update 2011-08 allows entities testing goodwill for impairment the option of performing a qualitative (“step 0”) assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that, based on that assessment, it is more likely than not that its fair value is less than its carrying amount.

The Predecessor applied the qualitative step 0 analysis to its reporting unit for the annual impairment test performed as of May 1, 2014. For this test, the Predecessor assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The results of this assessment indicated that it is not more likely than not that its reporting unit fair value is less than the reporting unit carrying value.

The Predecessor considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. No such indicators were noted that would require a subsequent goodwill impairment test during the nine months ended September 30, 2014.

 

6. Asset Retirement Obligations

Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate-regulated subsidiaries are classified as Regulatory liabilities on the Condensed Combined Balance Sheets (unaudited).

 

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Changes in the Predecessor’s liability for asset retirement obligations for the nine months ended September 30, 2014 and 2013 are presented in the table below:

 

     2014     2013  
     (in millions)  

Beginning Balance

   $ 26.3      $ 19.2   

Accretion expense

     1.1        0.9   

Additions

     2.0        6.8   

Settlements

     —          (0.2

Change in estimated cash flows

     (0.2     (0.4
  

 

 

   

 

 

 

Ending Balance

   $ 29.2      $ 26.3   
  

 

 

   

 

 

 

 

7. Regulatory Matters

Significant Rate Developments. On January 30, 2014, Columbia Gas Transmission received FERC approval of its December 2013 filing to recover costs associated with the first year of its comprehensive system modernization program. During 2013, Columbia Gas Transmission completed more than 30 individual projects representing a total investment of about $300 million. The program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Recovery of the 2013 investments began on February 1, 2014.

The second year of the program also includes planned modernization investments of approximately $330 million. Columbia Gas Transmission and its customers have agreed to the initial five years of the comprehensive modernization program, with an opportunity to mutually extend the agreement.

Cost Recovery Trackers. A significant portion of the regulated transmission and storage companies’ revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under section 4 of the Natural Gas Act. However, as certain operating costs of the Predecessor’s regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas, which is settled in-kind and reflected net of recoveries in operating expenses. The FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include third-party pipeline transportation, electric compression, certain environmental related expenses, and certain operational purchases and sales of natural gas.

 

8. Equity Method Investments

Certain investments of the Predecessor are accounted for under the equity method of accounting. Income and losses from Millennium Pipeline, Hardy Storage and Pennant are reflected in “Equity Earnings in Unconsolidated Affiliates” on the Predecessor’s Condensed Combined Statements of Operations (unaudited). These investments are integral to the Predecessor’s business. Contributions are made to these equity investees to fund the Predecessor’s share of capital projects.

Contributions made to Millennium Pipeline were $2.6 million and $9.0 million for the nine months ended September 30, 2014 and 2013, respectively. Millennium Pipeline distributed $26.1 million and $17.1 million of earnings to Columbia Gas Transmission during the nine months ended September 30, 2014 and 2013, respectively.

No contributions were made to Hardy Storage during the nine months ended September 30, 2014 and 2013. Hardy Storage distributed $1.5 million and $1.9 million of available accumulated earnings to NiSource during the nine months ended September 30, 2014 and 2013, respectively.

 

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Contributions made to Pennant were $61.2 million and $68.0 million for the nine months ended September 30, 2014 and 2013, respectively. No distributions were received from Pennant during the nine months ended September 30, 2014 and 2013, respectively.

 

9. Income Taxes

The Predecessor’s interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items. The effective tax rates for the nine months ended September 30, 2014 and 2013 were 36.9% and 36.5%, respectively. These effective tax rates differ from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences.

There were no material changes recorded in the nine months ended September 30, 2014 to the Predecessor’s uncertain tax positions as of December 31, 2013.

 

10. Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of the Predecessor. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees of the Predecessor. The majority of employees may become eligible for these benefits if they reach retirement age while working for the Predecessor. The expected cost of such benefits is accrued during the employees’ years of service. The Predecessor’s current rates charged to its customers include postretirement benefit costs. Cash contributions are remitted to grantor trusts.

The Predecessor is a participant in the consolidated NiSource defined benefit retirement plans (the Plans), and therefore, the Predecessor is allocated a ratable portion of NiSource’s grantor trusts for the Plans in which its employees and retirees participate. As a result, the Predecessor follows multiple employer accounting under the provisions of GAAP.

For the nine months ended September 30, 2014 and 2013, the Predecessor has made no contribution to its pension plans and has contributed $7.7 million to its other postretirement benefit plans.

The following table provides the components of the Predecessor’s allocation of net periodic benefits cost for the nine months ended September 30, 2014 and 2013:

 

     Pension Benefits     Other Postretirement Benefits  
         2014             2013             2014             2013      
     (in millions)  

Components of Net Periodic Benefit

        

Cost (Income)

        

Service cost

   $ 3.7     $ 3.8     $ 0.8     $ 1.1  

Interest cost

     10.3       9.3       3.5       3.7  

Expected return on assets

     (17.9     (16.7     (12.3     (10.2

Amortization of prior service (credit) cost

     (0.7     (0.7     0.1       0.1  

Recognized actuarial loss

     4.9       8.3       (0.1 )     0.8  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Periodic Benefit Cost (Income)

   $ 0.3     $ 4.0     $ (8.0   $ (4.5

Settlement loss

     —         11.8       —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Net Periodic Benefit Cost (Income)

   $ 0.3     $ 15.8     $ (8.0   $ (4.5
  

 

 

   

 

 

   

 

 

   

 

 

 

In 2013, NiSource pension plans had lump sum payouts exceeding the plan’s 2013 service cost plus interest cost and, therefore, settlement accounting was required.

 

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11. Fair Value

The Predecessor has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits and short-term borrowings—affiliated. The Predecessor’s long-term debt—affiliated are recorded at historical amounts.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Long-term debt—affiliated. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the nine months ended September 30, 2014 and the year ended December 31, 2013, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

The carrying amount and estimated fair values of financial instruments were as follows:

 

     Carrying
Amount as of
September 30, 2014
     Estimated Fair
Value as of
September 30, 2014
     Carrying
Amount as of
December 31,
2013
     Estimated Fair
Value as of
December 31,
2013
 
            (in millions)         

Long-term debt—affiliated

   $ 1,370.9       $ 1,434.7       $ 819.8       $ 835.7   

 

12. Other Commitments and Contingencies

A. Other Legal Proceedings. In the normal course of its business, the Predecessor has been named as a defendant in various legal proceedings. In the opinion of the Predecessor, the ultimate disposition of these currently asserted claims will not have a material impact on the Predecessor’s combined financial statements.

B. Environmental Matters. The Predecessor operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. The Predecessor believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.

It is the Predecessor’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. The Predecessor expects a significant portion of environmental assessment and remediation costs to be recoverable through rates.

As of September 30, 2014 and December 31, 2013, the Predecessor recorded an accrual of approximately $2.8 million and $8.8 million, respectively, to cover environmental remediation at various sites. The current portion of this accrual is included in “Legal and environmental” in the Condensed Combined Balance Sheets (unaudited). The noncurrent portion is included in “Other noncurrent liabilities” in the Condensed Combined Balance Sheets (unaudited). The Predecessor accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. These expenditures are not currently estimable at some sites. The Predecessor periodically adjusts its accrual as information is collected and estimates become more refined.

Air

In April 2014, the Pennsylvania Department of Environmental Protection proposed a rule, Additional RACT Requirements for Major Sources of NOx and VOCs, which may require emissions reductions from several of

 

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Columbia Gas Transmission’s turbines and reciprocating engines. The rule is expected to be finalized by the end of 2014. Although costs cannot be estimated at this time, it is possible costs could be material. The Predecessor will continue to monitor developments in this matter.

Waste

Columbia Gas Transmission continues to conduct characterization and remediation activities at specific sites under a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”). The Predecessor utilizes a probabilistic model to estimate its future remediation costs related to the AOC. The model was prepared with the assistance of a third party and incorporates the Predecessor and general industry experience with remediating sites. The Predecessor completes an annual refresh of the model in the second quarter of each fiscal year. No material changes to the liability were noted as a result of the refresh completed as of September 30, 2014. The total remaining liability at Columbia Gas Transmission related to the facilities subject to remediation was $2.8 million and $8.7 million at September 30, 2014 and December 31, 2013, respectively. The liability represents Columbia Gas Transmission’s best estimate of the cost to remediate the facilities or manage the sites. Remediation costs are estimated based on the information available, applicable remediation standards, and experience with similar facilities. Columbia Gas Transmission expects that the remediation for these facilities will be substantially completed in 2015.

 

13. Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss for the nine months ended September 30, 2014 and 2013:

 

     Gains and Losses
on Cash Flow
Hedges(1)
    Pension and
OPEB  Items(1)
    Accumulated
Other
Comprehensive
Loss(1)
 
     (in millions)  

Balance as of January 1, 2014

   $ (17.6   $ (0.1   $ (17.7
  

 

 

   

 

 

   

 

 

 

Other comprehensive income before reclassifications

     —          —          —     

Amounts reclassified from accumulated other comprehensive income

     0.8        —          0.8   
  

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     0.8        —          0.8   
  

 

 

   

 

 

   

 

 

 

Balance as of September 30, 2014

   $ (16.8   $ (0.1   $ (16.9
  

 

 

   

 

 

   

 

 

 

Balance as of January 1, 2013

   $ (18.7   $ (0.1   $ (18.8
  

 

 

   

 

 

   

 

 

 

Other comprehensive income before reclassifications

     —          —          —     

Amounts reclassified from accumulated other comprehensive income

     0.8        (0.2     0.6   
  

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     0.8        (0.2     0.6   
  

 

 

   

 

 

   

 

 

 

Balance as of September 30, 2013

   $ (17.9   $ (0.3   $ (18.2
  

 

 

   

 

 

   

 

 

 

 

(1) 

All amounts are net of tax. Amounts in parentheses indicate debits.

Equity Method Investment

As Millennium Pipeline is an equity method investment, the Predecessor is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining proportional share of unrecognized loss at September 30, 2014 of $16.8 million, net of tax, related to terminated interest rate swaps is being amortized over the period

 

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ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $16.8 million and $17.9 million at September 30, 2014 and 2013, respectively, is included in gains and losses on cash flow hedges above.

 

14. Other, Net

 

     Nine Months Ended September 30,  
         2014             2013      
     (in millions)  

AFUDC Equity

   $ 8.2      $ 4.6   

Miscellaneous(1)

     (0.2     10.7   
  

 

 

   

 

 

 

Total Other, net

   $ 8.0      $ 15.3   
  

 

 

   

 

 

 

 

(1) 

Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

 

15. Supplemental Cash Flow Information

The following table provides additional information regarding the Predecessor’s Condensed Combined Statements of Cash Flows (unaudited) for the nine months ended September 30, 2014 and 2013:

 

     Nine Months Ended September 30,  
         2014              2013      
     (in millions)  

Supplemental Disclosures of Cash Flow Information

     

Non-cash transactions:

     

Capital expenditures included in current liabilities

   $ 96.4       $ 101.4   

Schedule of interest and income taxes paid:

     

Cash paid for interest, net of interest capitalized amounts

   $ 55.0       $ 37.9   

Cash paid for income taxes

     48.3         20.7   

 

16. Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party, accounted for greater than 10% of total operating revenues for the nine months ended September 30, 2014 and 2013. The following table provides the customer operating revenues and the customer operating revenues as a percentage of total operating revenues for the nine months ended September 30, 2014 and 2013:

 

     2014     2013  
     Total Operating
Revenues
     Percentage of
Total Operating
Revenues
    Total Operating
Revenues
     Percentage of
Total Operating
Revenues
 
     (in millions)  

Columbia Gas of Ohio

   $ 119.8         11.9   $ 119.1         13.9

There was no other single customer that accounted for greater than 10% of total operating revenues for the nine months ended September 30, 2014 and 2013. The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of the Predecessor.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of NiSource Inc.

Merrillville, Indiana

We have audited the accompanying combined balance sheets of Columbia Pipeline Partners LP Predecessor (the “Company”) as of December 31, 2013 and 2012, and the related combined statements of operations, comprehensive income, parent net equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the financial position of Columbia Pipeline Partners LP Predecessor at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Chicago, Illinois

September 26, 2014

 

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Columbia Pipeline Partners LP Predecessor Combined Balance Sheets

 

     As of December 31,  
     2013     2012  
     (in millions)  

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 0.3      $ 0.6   

Accounts receivable (less reserve of $0.1 and $0.3, respectively)

     128.0        126.7   

Accounts receivable—affiliated

     94.4        76.7   

Income tax receivable

     1.4        25.7   

Materials and supplies, at average cost

     24.8        22.6   

Exchange gas receivable

     49.2        26.0   

Regulatory assets

     12.3        13.8   

Deferred property taxes

     46.8        42.6   

Deferred income taxes

     9.7        45.5   

Prepayments and other

     11.2        15.1   
  

 

 

   

 

 

 

Total Current Assets

     378.1        395.3   
  

 

 

   

 

 

 

Investments

    

Unconsolidated affiliates

     364.5        233.6   

Other investments

     12.3        18.2   
  

 

 

   

 

 

 

Total Investments

     376.8        251.8   
  

 

 

   

 

 

 

Property, Plant and Equipment

    

Property, plant and equipment

     7,191.4        6,562.0   

Accumulated depreciation and amortization

     (2,888.0     (2,820.5
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     4,303.4        3,741.5   
  

 

 

   

 

 

 

Other Noncurrent Assets

    

Regulatory assets

     130.3        218.2   

Goodwill

     1,975.5        1,975.5   

Postretirement and postemployment benefits assets

     93.1        38.6   

Deferred charges and other

     4.6        2.3   
  

 

 

   

 

 

 

Total Other Noncurrent Assets

     2,203.5        2,234.6   
  

 

 

   

 

 

 

Total Assets

   $ 7,261.8      $ 6,623.2   
  

 

 

   

 

 

 

LIABILITIES AND PARENT NET EQUITY

    

Current Liabilities

    

Short-term borrowings—affiliated

   $ 719.6      $ 328.7   

Accounts payable

     71.9        71.4   

Accounts payable—affiliated

     41.3        24.9   

Customer deposits

     11.5        10.2   

Taxes accrued

     96.0        129.2   

Exchange gas payable

     48.1        25.3   

Deferred revenue

     14.9        7.3   

Regulatory liabilities

     0.8        81.7   

Legal and environmental

     8.4        12.9   

Other accruals

     84.8        79.1   
  

 

 

   

 

 

 

Total Current Liabilities

     1,097.3        770.7   
  

 

 

   

 

 

 

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Table of Contents
     As of December 31,  
     2013     2012  
     (in millions)  

Noncurrent Liabilities

    

Long-term debt—affiliated

     819.8        754.7   

Deferred income taxes

     1,077.0        926.4   

Deferred revenue

     17.1        32.5   

Accrued liability for postretirement and postemployment benefits

     32.7        91.4   

Regulatory liabilities

     282.3        261.4   

Asset retirement obligations

     26.3        19.2   

Other noncurrent liabilities

     9.4        27.4   
  

 

 

   

 

 

 

Total Noncurrent Liabilities

     2,264.6        2,113.0   
  

 

 

   

 

 

 

Total Liabilities

     3,361.9        2,883.7   
  

 

 

   

 

 

 

Commitments and Contingencies (Refer to Note 13)

    

Parent Net Equity

    

Net parent investment

     3,917.6        3,758.3   

Accumulated other comprehensive loss

     (17.7     (18.8
  

 

 

   

 

 

 

Total Parent Net Equity

     3,899.9        3,739.5   
  

 

 

   

 

 

 

Total Liabilities and Parent Net Equity

   $ 7,261.8      $ 6,623.2   
  

 

 

   

 

 

 

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Combined Statements of Operations

 

     Year Ended December 31,  
     2013     2012     2011  
     (in millions)  

Operating Revenues

      

Transportation revenues

   $ 850.9      $ 679.4      $ 678.6   

Transportation revenues—affiliated

     94.3        96.0        96.8   

Storage revenues

     142.8        144.3        144.1   

Storage revenues—affiliated

     53.6        52.4        52.0   

Other revenues

     37.8        28.3        34.1   
  

 

 

   

 

 

   

 

 

 

Total Operating Revenues

     1,179.4        1,000.4        1,005.6   
  

 

 

   

 

 

   

 

 

 

Operating Expenses

      

Operation and maintenance

     507.1        374.2        377.9   

Operation and maintenance—affiliated

     118.1        105.6        98.3   

Depreciation and amortization

     106.9        99.3        130.0   

(Gain)/loss on sale of assets

     (18.6     (0.6     0.1   

Property and other taxes

     62.2        59.2        56.6   
  

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     775.7        637.7        662.9   
  

 

 

   

 

 

   

 

 

 

Equity Earnings in Unconsolidated Affiliates

     35.9        32.2        14.6   
  

 

 

   

 

 

   

 

 

 

Operating Income

     439.6        394.9        357.3   
  

 

 

   

 

 

   

 

 

 

Other Income (Deductions)

      

Interest expense—affiliated

     (37.9     (29.5     (29.8

Other, net

     17.6        1.5        1.2   
  

 

 

   

 

 

   

 

 

 

Total Other Deductions, net

     (20.3     (28.0     (28.6
  

 

 

   

 

 

   

 

 

 

Income from Continuing Operations before Income Taxes

     419.3        366.9        328.7   

Income Taxes

     152.4        136.9        125.6   
  

 

 

   

 

 

   

 

 

 

Net Income

   $ 266.9      $ 230.0      $ 203.1   
  

 

 

   

 

 

   

 

 

 

Unaudited pro forma basic earnings per common unit (refer to Note 1Q)

   $ 0.67       

Unaudited pro forma diluted earnings per common unit (refer to Note 1Q)

   $ 0.67       
  

 

 

   

 

 

   

 

 

 

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Combined Statements of Comprehensive Income

 

     Year Ended December 31,  
     2013      2012     2011  
     (in millions, net of taxes)  

Net Income

   $ 266.9       $ 230.0      $ 203.1   

Other comprehensive income (loss):

       

Net unrealized gain on cash flow hedges(1)

     1.1         1.0        1.4   

Unrecognized pension and OPEB costs(2)

     —           (0.1     —     
  

 

 

    

 

 

   

 

 

 

Total other comprehensive income

     1.1         0.9        1.4   
  

 

 

    

 

 

   

 

 

 

Total Comprehensive Income

   $ 268.0       $ 230.9      $ 204.5   
  

 

 

    

 

 

   

 

 

 

 

(1) Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.6 million tax expense in 2013 and 2012 and zero tax expense in 2011.
(2) Unrecognized pension benefit and OPEB costs, net of $0.1 million tax benefit in 2012.

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Combined Statements of Cash Flows

 

     Year Ended December 31,  
     2013     2012     2011  
     (in millions)  

Operating Activities

      

Net Income

   $ 266.9      $ 230.0      $ 203.1   

Adjustments to Reconcile Net Income to Net Cash from Continuing Operations

      

Depreciation and amortization

     106.9        99.3        130.0   

Deferred income taxes and investment tax credits

     179.9        44.7        76.8   

Deferred revenue

     (0.5     (4.1     1.1   

Stock compensation expense and 401(k) profit sharing contribution

     2.2        3.2        1.7   

(Gain)/loss on sale of assets

     (18.6     (0.6     0.1   

Income from unconsolidated affiliates

     (35.9     (32.2     (14.6

AFUDC equity

     (6.8     (1.4     —     

Distributions of earnings received from equity investees

     32.1        34.9        18.8   

Changes in Assets and Liabilities

      

Accounts receivable—affiliated

     (7.6     14.8        21.2   

Accounts receivable

     2.5        (14.2     (11.5

Income tax receivable

     24.3        (25.7     6.9   

Accounts payable—affiliated

     16.3        (6.0     (10.6

Accounts payable

     5.5        16.7        (7.9

Customer deposits

     1.3        1.3        2.6   

Taxes accrued

     (28.5     33.8        35.9   

Exchange gas receivable/payable

     (0.5     1.4        (17.8

Other accruals

     0.4        0.8        9.9   

Prepayments and other current assets

     (2.6     0.8        (10.0

Regulatory assets/liabilities

     42.6        56.5        30.5   

Postretirement and postemployment benefits

     (113.3     17.0        (41.3

Deferred charges and other noncurrent assets

     2.5        13.4        (5.0

Other noncurrent liabilities

     (15.1     (9.5     15.4   
  

 

 

   

 

 

   

 

 

 

Net Cash Flows from Operating Activities

     454.0        474.9        435.3   
  

 

 

   

 

 

   

 

 

 

Investing Activities

      

Capital expenditures

     (674.8     (431.7     (312.3

Insurance recoveries

     6.4        6.5        —     

Changes in short-term lendings—affiliated

     (10.0     (24.4     12.4   

Proceeds from disposition of assets

     15.4        22.7        4.0   

Contributions to equity investees

     (125.5     (20.4     (6.2

Other investing activities

     (8.9     (8.2     (5.1
  

 

 

   

 

 

   

 

 

 

Net Cash Flows used for Investing Activities

     (797.4     (455.5     (307.2
  

 

 

   

 

 

   

 

 

 

Financing Activities

      

Changes in short-term borrowings—affiliated

     391.0        (111.1     61.9   

Issuance of long-term debt—affiliated

     65.1        460.0        —     

Repayments of long-term debt—affiliated

     —          (158.7     —     

Dividends to parent

     (113.0     (209.0     (190.0
  

 

 

   

 

 

   

 

 

 

Net Cash Flows from (used for) Financing Activities

     343.1        (18.8     (128.1
  

 

 

   

 

 

   

 

 

 

Change in cash and cash equivalents

     (0.3     0.6        —     

Cash and cash equivalents at beginning of period

     0.6        —          —     
  

 

 

   

 

 

   

 

 

 

Cash and Cash Equivalents at End of Period

   $ 0.3      $ 0.6      $ —     
  

 

 

   

 

 

   

 

 

 

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Combined Statements of Parent Net Equity

 

     Net Parent
Investment
    Accumulated
Other
Comprehensive
Income/(Loss)
    Total  
     (in millions)  

Balance January 1, 2011

   $ 3,711.5      $ (21.1   $ 3,690.4   
  

 

 

   

 

 

   

 

 

 

Net Income

     203.1        —          203.1   

Dividends to parent

     (190.0     —          (190.0

Other comprehensive income, net of tax

     —          1.4        1.4   

Net transfers from parent

     7.0        —          7.0   
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2011

   $ 3,731.6      $ (19.7   $ 3,711.9   
  

 

 

   

 

 

   

 

 

 

Net Income

     230.0        —          230.0   

Dividends to parent

     (209.0     —          (209.0

Other comprehensive income, net of tax

     —          0.9        0.9   

Net transfers from parent(1)

     5.7        —          5.7   
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2012

   $ 3,758.3      $ (18.8   $ 3,739.5   
  

 

 

   

 

 

   

 

 

 

Net Income

     266.9        —          266.9   

Dividends to parent

     (113.0     —          (113.0

Other comprehensive income, net of tax

     —          1.1        1.1   

Net transfers from parent

     5.4        —          5.4   
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2013

   $ 3,917.6      $ (17.7   $ 3,899.9   
  

 

 

   

 

 

   

 

 

 

 

(1) Includes $5.5 million forgiveness of intercompany payables to parent.

The accompanying Notes to Combined Financial Statements are an integral part of these statements.

 

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Columbia Pipeline Partners LP Predecessor Notes to Combined Financial Statements

 

1. Nature of Operations and Summary of Significant Accounting Policies

A.    Company Structure and Basis of Presentation. The accompanying combined financial statements of Columbia Pipeline Partners LP Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering (the “offering”) of common units representing limited partner interests in Columbia Pipeline Partners LP (the “Partnership”). Formed in Delaware on December 5, 2007, the Partnership is a subsidiary of NiSource Inc. (“NiSource”). NiSource is a Delaware corporation and holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the midwest to New England. The Predecessor is comprised of NiSource’s Columbia Pipeline Group Operations reportable segment which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource.

As part of the offering, NiSource will contribute substantially all of the Predecessor’s assets and operations to CPG OpCo LP (“Columbia OpCo”), a Delaware limited partnership formed by Columbia Energy Group (“CEG”), a wholly owned subsidiary of NiSource and CPG OpCo GP LLC (“OpCo GP”), a wholly owned subsidiary of the Partnership. The Partnership will own a 14.6% limited partner interest in Columbia OpCo and CEG will retain the remaining 85.4% limited partner interest. CPP GP LLC (“MLP GP”), a wholly owned subsidiary of NiSource, will serve as the general partner for the Partnership. OpCo GP will serve as the general partner for Columbia OpCo. Columbia Pipeline Group Services Company will provide services to the Partnership pursuant to an omnibus agreement. MLP GP, the Partnership, Columbia OpCo and OpCo GP have all adopted December 31 fiscal year ends.

The Predecessor is engaged in regulated gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under a tariff and at rates subject to FERC approval.

The Predecessor’s accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the basis of NiSource’s historical ownership of the Predecessor’s assets and its operations. These financial statements include the Predecessor’s accounts and those of its wholly owned subsidiaries, Columbia Gas Transmission, LLC, Columbia Gulf Transmission, LLC, Columbia Midstream Group, LLC, Columbia Energy Ventures, LLC, Crossroads Pipeline Company, Columbia Pipeline Group Services Company and Central Kentucky Transmission Company. As the financial statements do not include a common parent company, the financial statements are presented as combined. Also included in the combined financial statements are equity method investments Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C., and Pennant Midstream, LLC. All intercompany transactions and balances have been eliminated. A direct ownership relationship does not exist among the entities comprising the Predecessor; therefore the net investment in the Predecessor is shown as Parent Net Equity in lieu of owner’s equity in the combined financial statements.

On September 26, 2014, the NiSource board of directors approved in principle the spin-off of NiSource’s natural gas pipeline and related businesses (which comprises substantially all of Columbia Pipeline Partners LP Predecessor) through a distribution to NiSource stockholders of all of the outstanding common stock of HoldCo. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions.

Subsequent events have been evaluated through September 26, 2014, the date these financial statements were available to be issued. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the financial statements.

 

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B.    Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

C.    Cash and Cash Equivalents. Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.

D.    Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is the Predecessor’s best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

E.    Basis of Accounting for Rate-Regulated Subsidiaries. The Predecessor accounts for and reports assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Combined Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

In the event that regulation significantly changes the opportunity for the Predecessor to recover its costs in the future, all or a portion of the Predecessor’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of the Predecessor’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of regulatory accounting, the Predecessor would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, the Predecessor’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Refer to Note 8, “Regulatory Matters,” in the Notes to Combined Financial Statements for additional information.

F.    Property, Plant and Equipment and Related AFUDC and Maintenance. Property, plant and equipment is stated at cost. The Predecessor’s regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. The Predecessor’s non-regulated companies depreciate non-mineral related assets on a component basis on a straight-line basis over the remaining service lives of the properties.

The Predecessor capitalizes AFUDC on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. The pre-tax rate for AFUDC debt was 2.5% in 2013, 2.1% in 2012 and 1.6% in 2011 and AFUDC equity was 3.2% in 2013 and 1.7% in 2012. The Predecessor did not record AFUDC equity in 2011. Short-term borrowings were primarily used to fund construction efforts for all three years presented.

The Predecessor follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.

G.    Gas Stored-Base Gas. Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were no purchases of base gas during 2013 or 2012. Refer to Note 4, “Gain on Sale of Assets,” in the Notes to Combined Financial

 

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Statements for information regarding the sale of storage base gas in 2013. Gas stored-base gas is included in Property, plant and equipment on the Combined Balance Sheets.

H.    Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. The Predecessor amortized $5.0 million in 2013, $3.8 million in 2012 and $4.2 million in 2011 related to software costs. The Predecessor’s unamortized software balance was $12.7 million and $16.6 million at December 31, 2013 and 2012, respectively.

I.    Goodwill. The Predecessor has approximately $2 billion in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia Energy Group acquisition on November 1, 2000. Refer to Note 6, “Goodwill,” in the Notes to Combined Financial Statements for additional information.

J.    Impairments. An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long lived asset is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.

K.    Revenue Recognition. Revenue is recognized as services are performed. Revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.

The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.

The Predecessor provides shorter term transportation services, for which cash is received at inception of the service period and is recorded as deferred revenue and recognized as income over the period the services are provided.

Revenues from storage are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

Deferred revenue includes a gain on conveyances related to pooling of assets (production rights) in a joint undertaking intended to find, develop, or produce oil or gas from a particular property or group of properties. The gain was initially deferred as the Predecessor has a substantial obligation for future performance. As the obligation for future performance is satisfied the deferred revenue is relieved and the associated gain is recognized. Refer to Note 4, “Gain on Sale of Assets,” in the Notes to Combined Financial Statements for further information.

The Predecessor includes the subsidiary CEVCO, which owns the mineral rights to over 450,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $21.2 million, $18.5 million and $14.5 million for the years ended December 31, 2013, 2012, and 2011, respectively, and are included in “Other revenues” on the Combined Statement of Operations.

L.    Estimated Rate Refunds. The Predecessor collects revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.

 

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M.    Accounting for Exchange and Balancing Arrangements of Natural Gas. The Predecessor enters into balancing and exchange arrangements of natural gas as part of their operations. The Predecessor records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on the Predecessor’s Combined Balance Sheets, as appropriate.

N.    Income Taxes and Investment Tax Credits. The Predecessor records income taxes to recognize full inter period tax allocations. Under the liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Previously recorded investment tax credits of the Predecessor were deferred on the balance sheet and are being amortized to book income over the regulatory life of the related properties to conform to regulatory policy. To the extent certain deferred income taxes of the Predecessor are recoverable or payable through future rates, regulatory assets and liabilities have been established.

The Predecessor joins in the filing of consolidated federal and state income tax returns with its parent company, NiSource. The Predecessor is party to an agreement (“Tax Allocation Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Allocation Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, the Tax Allocation Agreement provides that tax benefits associated with NiSource parent’s tax losses, excluding tax benefits from interest expense on acquisition debt, are allocated to and reduce the income tax liability of all NiSource subsidiaries having a positive separate company tax liability in a particular tax year.

The amounts of such tax benefits allocated to the Predecessor for the 2013, 2012 and 2011 tax years that were recorded in equity, were $5.4 million, $0.2 million and $4.4 million, respectively.

O.    Environmental Expenditures. The Predecessor accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accrual for estimated environmental expenditures are recorded on the Combined Balance Sheets in “Legal and environmental” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. The Predecessor establishes regulatory assets on the Combined Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Refer to Note 13, “Other Commitments and Contingencies,” in the Notes to Combined Financial Statements for further information.

P.    Accounting for Investments. The Predecessor accounts for its ownership interests in Millennium Pipeline Company, L.L.C. (“Millennium Pipeline”) using the equity method of accounting. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where the Predecessor (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.

Columbia Gas Transmission also owns a 100% interest in Columbia Hardy Corporation, which has a 50% interest in Hardy Storage. The Predecessor reflects the investment in Hardy Storage as an equity investment.

Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, new wet natural gas gathering pipeline infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. Columbia Midstream and Hilcorp jointly own Pennant with Columbia Midstream serving as the operator of Pennant and its facilities. The Predecessor accounts for the joint venture under the equity method of accounting.

 

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Q.    Supplemental Pro Forma Information (Unaudited). Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, the Partnership intends to distribute approximately $500.0 million in cash to parent. This distribution will be paid with offering proceeds. The unaudited pro forma basic and diluted earnings per common unit for the year ended December 31, 2013 assumed 29,861,398 common units were outstanding in the period. The 29,861,398 common units consists of 6,811,398 units issued to CEG plus an additional 23,050,000 units, which is the number of common units we would have been required to issue to fund the $500.0 million distribution. For the year ended December 31, 2013, pro forma basic and diluted net income per common unit would have been $0.67.

 

2. Recent Accounting Pronouncements

In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that represents a strategic shift that has or will have a major impact on its operations and financial results is a discontinued operation. The Predecessor is required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. The Predecessor is currently evaluating what impact, if any, adoption of ASU 2014-08 will have on its Combined Financial Statements and Notes to Combined Financial Statements.

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Predecessor is required to adopt ASU 2014-09 for periods beginning after December 15, 2016, including interim periods, and the standard is to be applied retrospectively. Early adoption is not permitted. The Predecessor is currently evaluating the impact the adoption of ASU 2014-09 will have on our Combined Financial Statements and Notes to Combined Financial Statements.

 

3. Transactions with Affiliates

In the normal course of business, the Predecessor engages in transactions with subsidiaries of NiSource. Transactions with affiliates are summarized in the tables below:

Statement of Operations.

 

     Year ended December 31,  
     2013      2012      2011  
     (in millions)  

Transportation revenues

   $ 94.3       $ 96.0       $ 96.8   

Storage revenues

     53.6         52.4         52.0   

Other revenues

     0.3         0.3         0.2   

Operation and maintenance expense

     118.1         105.6         98.3   

Interest expense

     37.9         29.5         29.8   

Interest income

     0.5         0.5         0.5   

 

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Balance Sheet.

 

     At December 31,  
     2013      2012  
     (in millions)  

Accounts receivable

   $ 94.4       $ 76.7   

Short-term borrowings

     719.6         328.7   

Accounts payable

     41.3         24.9   

Long-term debt

     819.8         754.7   

Transportation, Storage and Other Revenues. The Predecessor provides natural gas transportation, storage and other services to subsidiaries of NiSource.

Operation and Maintenance Expense. The Predecessor receives executive, financial, legal, information technology and other administrative and general services from an affiliate, NiSource Corporate Services. Expenses incurred as a result of these services consist of employee compensation and benefits, outside services and other expenses. The Predecessor is charged directly or allocated using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable; however, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity.

Interest Expense and Income. The Predecessor was charged interest for long-term debt of $40.6 million in 2013, $26.1 million in 2012 and $25.4 million in 2011, offset by associated AFUDC of $6.8 million in 2013, $2.3 million in 2012 and $0.8 million in 2011. Refer to Note 1F “Property, Plant and Equipment and Related AFUDC and Maintenance” in the Notes to Combined Financial Statements for more information on AFUDC.

NiSource Corporate Services administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. The subsidiaries of the Predecessor participated in the money pool for all of the periods presented in the financial statements. The cash accounts maintained by subsidiaries of the Predecessor are swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and the Predecessor. The amount of interest expense and income for short-term borrowings is determined by the net position of each subsidiary of the Predecessor in the money pool. The money pool weighted-average interest rate at December 31, 2013 and 2012 was 0.87% and 1.42%, respectively. The interest expense for short-term borrowings charged in 2013, 2012 and 2011 was $4.1 million, $5.7 million and $5.2 million, respectively.

Accounts Receivable. The Predecessor includes in accounts receivable amounts due from the money pool discussed above at December 31, 2013 and 2012 of $63.4 million and $53.4 million for subsidiaries in a net deposit position. Also included in the balance at December 31, 2013 and 2012 are amounts due from subsidiaries of NiSource for transportation and storage services of $31.0 million and $23.3 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Combined Statement of Cash Flows. All other affiliated receivables are included as Operating Activities.

Short-term Borrowings. The balance at December 31, 2013 and 2012 includes all subsidiaries of the Predecessor in a net borrower position of the money pool discussed above. Net cash flows related to short-term borrowings are included as Financing Activities on the Combined Statement of Cash Flows.

Accounts Payable. The affiliated accounts payable primarily includes amounts due for services received from NiSource Corporate Services and interest payable to NiSource Finance.

 

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Long-term Debt. The Predecessor’s long-term financing requirements are satisfied through borrowings from NiSource Finance. Details of the long-term debt balance are summarized in the table below:

 

                  At December 31,  
                  2013      2012  

Origination Date

   Interest Rate     Maturity Date      (in millions)  

November 28, 2005

     5.41     November 30, 2015       $ 115.9       $ 115.9   

November 28, 2005

     5.45     November 28, 2016         45.3         45.3   

November 28, 2005

     5.92     November 28, 2025         133.5         133.5   

November 28, 2012

     4.63     November 28, 2032         45.0         45.0   

November 28, 2012

     4.94     November 30, 2037         95.0         95.0   

December 19, 2012

     5.16     December 21, 2037         55.0         55.0   

November 28, 2012

     5.26     November 28, 2042         170.0         170.0   

December 19, 2012

     5.49     December 18, 2042         95.0         95.0   

December 9, 2013

     4.75     December 31, 2016         65.1         —     
       

 

 

    

 

 

 

Total Long-term Debt

        $ 819.8       $ 754.7   
       

 

 

    

 

 

 

Dividends. The Predecessor paid dividends to the parent of $113.0 million, $209.0 million and $190.0 million in 2013, 2012, and 2011, respectively. There are no restrictions on the payment of dividends.

 

4. Gain on Sale of Assets

In 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million.

The Predecessor recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. Gains on conveyances of $7.3 million were recorded in earnings in 2013. As of December 31, 2013, deferred gains of approximately $30.0 million were deferred pending performance of future obligations and recorded in deferred revenue on the Combined Balance Sheets.

 

5. Property, Plant and Equipment

Property, plant and equipment includes materials, payroll and related costs such as taxes, pensions and other employee benefits, general and administrative costs and AFUDC.

The Predecessor’s property, plant and equipment on the Combined Balance Sheets are classified as follows:

 

     At December 31,  
     2013     2012  
     (in millions)  

Property, plant and equipment

    

Pipeline and other transmission assets

   $ 4,891.8      $ 4,433.7   

Storage facilities

     1,253.4        1,206.3   

Gas stored base gas

     299.5        303.3   

Gathering and processing facilities

     260.5        88.2   

Construction work in process

     238.2        319.5   

General plant, software, and other assets

     248.0        211.0   
  

 

 

   

 

 

 

Property, plant and equipment

     7,191.4        6,562.0   
  

 

 

   

 

 

 

Accumulated depreciation and amortization

     (2,888.0     (2,820.5
  

 

 

   

 

 

 

Net property, plant and equipment

   $ 4,303.4      $ 3,741.5   
  

 

 

   

 

 

 

 

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The table below lists the Predecessor’s applicable annual depreciation rates:

 

     Year Ended December 31,  
     2013      2012      2011  

Depreciation rates

        

Pipeline and other transmission assets

     1.50% - 2.55%         1.00% - 2.55%         1.00% - 2.55%   

Storage facilities

     2.19% - 3.50%         2.19% - 3.50%         2.19% - 3.50%   

Gathering and processing facilities

     1.67% - 2.50%         1.67% - 2.50%         1.67% - 2.50%   

General plant, software, and other assets

     1.00% - 10.00%         1.00% - 10.00%         1.00% - 10.00%   

 

6. Goodwill

In accordance with the provisions for goodwill accounting under GAAP, the Predecessor tests its goodwill for impairment annually as of May 1 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB. Columbia Transmission Operations, which is included in the Predecessor, has been determined to be a reporting unit. The Predecessor’s goodwill assets at December 31, 2013 and 2012 were approximately $2.0 billion pertaining to the acquisition of Columbia Energy Group on November 1, 2000.

The Predecessor completed a quantitative (“step 1”) fair value measurement of its reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded its carrying value, indicating that no impairment existed under the step 1 annual impairment test.

In estimating the fair value of Columbia Transmission Operations reporting unit for the May 1, 2012 test, the Predecessor used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for the reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Predecessor utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated using multiples and assumptions inherent in today’s market. The degree of judgment involved and reliability of inputs into each model were considered in weighting the various approaches. The resulting estimate of fair value of the reporting unit, using the weighted average of the income and market approaches, exceeded their carrying values, indicating that no impairment exists under step 1 of the annual impairment test.

Certain key assumptions used in determining the fair values of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Predecessor used the discount rate of 5.60% for Columbia Transmission Operations, resulting in excess fair value of approximately $1,643.0 million.

 

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In September 2011, FASB issued Accounting Standards Update 2011-08, which allows entities testing goodwill for impairment the option of performing a qualitative (“step 0”) assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that based on the qualitative step 0 assessment that it is more likely than not that its fair value is less than its carrying amount. The update was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

The Predecessor applied this guidance for its 2013 annual test and applied the qualitative step 0 analysis to its reporting unit for the annual impairment test performed as of May 1, 2013.

For the 2013 qualitative step 0 test performed as of May 1, 2013, the Predecessor assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit in its baseline May 1, 2012 test. The results of this assessment indicated that it is not more likely than not that its reporting unit fair values are less than the reporting unit carrying value.

The Predecessor considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below their carrying amounts and necessitate another goodwill impairment test. No such indicators were noted that would require additional goodwill impairment testing subsequent to May 1, 2013.

 

7. Asset Retirement Obligations

Changes in the Predecessor’s liability for asset retirement obligations for the years 2013 and 2012 are presented in the table below:

 

     2013     2012  
     (in millions)  

Beginning Balance

   $ 19.2      $ 17.8   

Accretion expense

     1.2        1.1   

Additions

     6.3        1.7   

Settlements

     (1.2     (0.3

Change in estimated cash flow

     0.8        (1.1
  

 

 

   

 

 

 

Ending Balance

   $ 26.3      $ 19.2   
  

 

 

   

 

 

 

The Predecessor’s asset retirement obligations above relate to obligations related to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, PCB remediation and asbestos removal at several compressor and measuring stations. The Predecessor recognizes that there are obligations to incur significant costs to retire wells associated with gas storage operations; however, the lives of these wells are indeterminable until management establishes plans for closure.

Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate-regulated subsidiaries are classified as Regulatory liabilities on the Combined Balance Sheets.

 

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8. Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets and liabilities of the Predecessor were comprised of the following items:

 

     At December 31,  
     2013      2012  
     (in millions)  

Assets

     

Unrecognized pension benefit and other postretirement benefit costs

   $ 101.9       $ 182.3   

Other postretirement costs

     13.8         17.9   

Environmental costs

     6.4         12.9   

Deferred taxes on AFUDC equity

     15.6         11.7   

Other

     4.9         7.2   
  

 

 

    

 

 

 

Total Regulatory Assets

   $ 142.6       $ 232.0   
  

 

 

    

 

 

 

 

     At December 31,  
     2013      2012  
     (in millions)  

Liabilities

     

Cost of removal

   $ 162.6       $ 169.6   

Regulatory effects of accounting for income taxes

     11.4         13.4   

Unrecognized pension benefit and other postretirement benefit costs

     20.0         0.4   

Other postretirement costs

     88.3         78.0   

Rate refunds and reserves

     —           81.7   

Other

     0.8         —     
  

 

 

    

 

 

 

Total Regulatory Liabilities

   $ 283.1       $ 343.1   
  

 

 

    

 

 

 

No regulatory assets are earning a return on investment at December 31, 2013. Regulatory assets of $25.6 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 30 years.

Assets:

Unrecognized pension benefit and other postretirement benefit costs—In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Other postretirement costs —Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs —Includes certain recoverable costs of remediating PCB contamination related to certain gas transmission facilities. Columbia Gas Transmission defers the costs as a regulatory asset in accordance with a regulatory order and is recovering these costs in rates. Recovery of such costs ceases January 31, 2015.

 

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Deferred taxes on AFUDC equity —ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. The Predecessor is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly—owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized.

Liabilities:

Cost of removal —Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate—regulated subsidiaries for future costs to be incurred.

Regulatory effects of accounting for income taxes —Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates in association with related depreciation on property.

Unrecognized pension benefit and other postretirement benefit costs —In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the benefits as a regulatory liability in accordance with regulatory orders or as a result of regulatory precedent.

Other postretirement costs —Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the Predecessor’s results, which exceeds the amount funded in the plan.

Rate refunds and reserves —Represents refunds owed to customers pursuant to the Columbia Gas Transmission Customer Settlement (the “Settlement”) in conjunction with Columbia Gas Transmission’s comprehensive interstate natural gas pipeline modernization program. These refunds were paid in March 2013.

Regulatory Matters

Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved the Settlement. In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, beginning in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter.

The Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25 million in revenues annually thereafter.

The Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system. The CCRM provides for a 14% revenue requirement with a portion designated as a recovery of increased taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission

 

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the opportunity to recover its revenue requirement associated with $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission’s transportation shippers. The CCRM will not exceed $300 million per year in investment in eligible facilities, subject to a 15% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term. On December 31, 2013, Columbia Gas Transmission made its first annual CCRM filing, with billing rates effective February 1, 2014. Through this filing, Columbia Gas Transmission will begin collecting its revenue requirements for the $299.2 million spent on eligible modernization facilities in 2013. For the first annual CCRM period, these revenue requirements will total approximately $38.9 million. On January 30, 2014, the FERC approved Columbia Gas Transmission’s first year CCRM filing.

Chesapeake, Virginia LNG Facility Modernization. In connection with long-term extensions of their expiring service agreements, the three customers of Columbia Gas Transmission’s Chesapeake, Virginia LNG peaking facility agreed to fund upgrades to modernize the facility. Under the settlement, Columbia Gas Transmission will invest approximately $30.0 million to upgrade the facility and each customer will extend its contract for 15 years. The settlement was filed with the FERC on February 28, 2013 and approved without modification on June 3, 2013. The project’s first phase was completed in the fourth quarter of 2013. The remainder of the project is expected to be completed by mid-2015.

Columbia Gulf Rate Case. On October 28, 2010, Columbia Gulf filed a rate case with the FERC, proposing a rate increase and tariff changes. Among other things, the filing proposed a revenue increase of approximately $50 million to cover increases in the cost of services, which includes adjustments for operation and maintenance expenses, capital investments, adjustments to depreciation rates and expense, rate of return, and increased federal, state and local taxes. On December 1, 2011, the FERC issued an order approving the settlement without change. The key elements of the settlement, which was a “black box agreement”, include: (1) increased base rate to $0.1520 per Dth and (2) establishing a postage stamp rate design. No protests to the order were filed and therefore, pursuant to the Settlement, the order became final on January 1, 2012 which made the settlement effective on February 1, 2012. On February 2, 2012, the Presiding Administrative Law Judge issued an initial decision granting a joint motion terminating the remaining litigation with the contesting party and allowing it to become a settling party. The FERC issued an order on March 15, 2012, affirming the initial decision, which terminated the remaining litigation with the contesting party. Refunds of approximately $16.0 million, accrued as of December 31, 2011, were disbursed to settling parties in March 2012.

Cost Recovery Trackers and other similar mechanisms. A significant portion of the Predecessor’s regulated companies’ revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under section 7 of the Natural Gas Act. However, as certain operating costs of the Predecessor’s regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas, the FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, environmental, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system as discussed above.

9. Equity Method Investments

Certain investments of the Predecessor are accounted for under the equity method of accounting. Income and losses from Millennium Pipeline, Hardy Storage and Pennant are reflected in Equity Earnings in Unconsolidated

 

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Affiliates on the Predecessor’s Statements of Combined Income. These investments are integral to the Predecessor’s business. Contributions are made to these equity investees to fund the Predecessor’s share of capital projects.

The following is a list of the Predecessor’s equity method investments at December 31, 2013:

 

Investee

   Type of Investment      % of Voting Power or
Interest Held

Hardy Storage Company, LLC

     LLC Membership       50.00%

Pennant Midstream, LLC

     LLC Membership       50.00%

Millennium Pipeline Company, L.L.C.

     LLC Membership       47.50%

As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in the aggregate, material to the Predecessor’s business, the following table contains condensed summary financial data. These investments are accounted for under the equity method of accounting and are recorded within Unconsolidated affiliates on the Predecessor’s Combined Balance Sheets and the Predecessor’s portion of the results is reflected in Equity Earnings in Unconsolidated Affiliates on the Predecessor’s Statements of Combined Income.

 

     Year Ended December 31,  
     2013      2012      2011  
     (in millions)  

Millennium Pipeline

        

Statement of Income Data:

        

Net Revenues

   $ 157.8       $ 152.3       $ 119.3   

Operating Income

     101.3         97.7         63.7   

Net Income

     63.0         57.1         20.5   

Balance Sheet Data:

        

Total Assets

     1,072.1         1,047.1         1,045.0   

Total Liabilities

     658.5         674.1         703.4   

Total Members’ Equity

     413.6         373.0         341.6   

Hardy Storage

        

Statement of Income Data:

        

Net Revenues

   $ 24.4       $ 24.4       $ 24.4   

Operating Income

     16.5         16.4         16.5   

Net Income

     10.6         10.0         9.7   

Balance Sheet Data:

        

Total Assets

     172.7         173.8         176.1   

Total Liabilities

     104.0         109.4         114.8   

Total Members’ Equity

     68.7         64.4         61.3   

Pennant

        

Statement of Income Data:

        

Net Revenues

   $ 2.0       $ —          $ —     

Operating Income

     1.3         —            —     

Net Income

     1.3         —            —      

Balance Sheet Data:

        

Total Assets

     266.0         47.4         —     

Total Liabilities

     11.4         2.0         —     

Total Members’ Equity

     254.6         45.4         —     

 

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Contributions made to Millennium Pipeline were $16.6 million, $17.5 million and $6.2 million for 2013, 2012 and 2011, respectively. Millennium Pipeline distributed $29.0 million, $31.4 million and $14.3 of earnings to Columbia Gas Transmission during 2013, 2012 and 2011, respectively.

No contributions were made to Hardy Storage during 2013, 2012 or 2011. Hardy Storage distributed $3.1 million, $3.5 million and $4.5 million of available accumulated earnings to NiSource during 2013, 2012 and 2011, respectively.

Contributions made to Pennant were $108.9 million, $2.9 million for 2013 and 2012, respectively. No contributions were made to Pennant during 2011. No distributions have been received from Pennant.

10. Income Taxes

The components of income tax expense were as follows:

 

     Year Ended December 31,  
     2013     2012     2011  
     (in millions)  

Income Taxes

      

Current

      

Federal

   $ (16.1   $ 80.7      $ 38.3   

State

     (11.4     11.5        10.5   
  

 

 

   

 

 

   

 

 

 

Total Current

     (27.5     92.2        48.8   
  

 

 

   

 

 

   

 

 

 

Deferred

      

Federal

     155.9        41.9        70.6   

State

     24.1        2.9        6.3   
  

 

 

   

 

 

   

 

 

 

Total Deferred

     180.0        44.8        76.9   
  

 

 

   

 

 

   

 

 

 

Deferred Investment Credits

     (0.1     (0.1     (0.1
  

 

 

   

 

 

   

 

 

 

Total Income Taxes

   $ 152.4      $ 136.9      $ 125.6   
  

 

 

   

 

 

   

 

 

 

Total income taxes from continuing operations were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:

 

     Year Ended December 31,  
     2013     2012     2011  
     (in millions)  

Book income from Continuing Operations before income taxes

   $ 419.3        $ 366.9        $ 328.7      

Tax expenses at statutory federal income tax rate

     146.8        35.0     128.4        35.0     115.0         35.0

Increases (reductions) in taxes resulting from:

             

State income taxes, net of federal income tax benefit

     8.2        1.9        9.4        2.5        10.9         3.3   

Amortization of deferred investment tax credits

     (0.1     —          (0.1     —          (0.1      —     

Nondeductible expenses

     0.9        0.2        0.9        0.2        —           —     

AFUDC-Equity

     (2.4     (0.6     (0.4     (0.1     0.2         —     

Other, net

     (1.0     (0.2     (1.3     (0.3     (0.4      (0.1
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Income Taxes

   $ 152.4        36.3   $ 136.9        37.3   $ 125.6         38.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

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The change in the overall effective tax rate between 2013 and 2012 was due primarily to the ratemaking treatment of AFUDC-Equity and state tax benefits due to corporate restructuring. The change in the overall tax rate between 2012 and 2011 was due primarily to state income tax rates.

On March 7, 2013, the Congressional Joint Committee on Taxation took no exception to the conclusions reached by the IRS in its 2008-2010 audit examination of NiSource. Therefore, in 2013, the Predecessor recognized a federal income tax receivable of $4.1 million that was related to the 2008 and 2009 tax. The Predecessor received payments of $27.4 million in 2013 of principal and interest from the IRS related to the audit examination. The recognition of the receivables did not materially affect tax expense or net income.

On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 (ATRA). ATRA, among other things, extended retroactively the research credit under Code section 41 until December 31, 2013, and also extended and modified 50% bonus depreciation for 2013. In general, 50% bonus depreciation is available for property placed in service before January 1, 2014, or in the case of certain property having longer production periods, before January 1, 2015. The Predecessor recorded the effects of ATRA in 2013. The retroactive extension of the research credit did not have a significant effect on net income.

In 2010, the Predecessor received permission from the IRS to change its method of accounting for capitalized overhead costs under Section 263A of the Internal Revenue Code. The change was effective for the 2009 tax year. In 2012, the IRS completed fieldwork for the audit for the years 2008-2010, and the change in method was accepted substantially as filed. Joint committee review was completed in 2013 without adjustment.

Tangible Property Regulations and Repairs

During the 2009, the Predecessor received permission from the IRS to change its tax method of capitalizing certain costs which it applied on a prospective basis to the federal and state income tax returns filed for its 2008 tax year.

On December 27, 2011, the United States Treasury Department and the IRS issued temporary and proposed regulations effective for years beginning on or after January 1, 2012 that, among other things, provided guidance on whether expenditures qualified as deductible repairs (the “Tangible Property Regulations”). In addition to repairs related rules, the proposed and temporary regulations provided additional guidance related to capitalization of tangible property. Among other things, these rules provide guidance for the treatment of materials and supplies, dispositions of property, and related elections. On March 15, 2012, the IRS issued a directive to discontinue exam activity related to positions on this issue taken on original tax returns for years beginning before January 1, 2012 (commonly referred to as the “Stand-down Position”).

On October 2, 2012 and later incorporated by reference in the Revenue Agent’s Report dated November 14, 2012 for the 2008 to 2010 tax years, the Predecessor received an audit adjustment that adopted the Stand-down Position. The effect of this adjustment is to allow the repairs claims as filed and to defer review until a new method is adopted in 2012 or a subsequent acceptable year.

On November 20, 2012, the Treasury Department and IRS issued Notice 2012-73, which in relevant part stated that (i) final regulations would be issued in 2013, and (ii) the final regulations will contain changes from the temporary regulations. The Notice in essence defers the requirement of adopting the temporary regulations until 2013 and the final regulations until 2014.

On September 13, 2013, the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers may elect early adoption of the regulations for the 2012 or 2013 tax year. The Predecessor does not plan to early adopt the regulations. The Predecessor has evaluated the impact of the final regulations and has determined that they do not materially affect the financial statements.

 

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Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

The principal components of the Predecessor’s net deferred tax liability were as follows:

 

     At December 31,  
     2013     2012  
     (in millions)  

Deferred tax liabilities

    

Accelerated depreciation and other property differences

   $ 1,088.0      $ 917.0   

Pension and other postretirement/postemployment benefits

     20.2        25.5   

Other regulatory assets

     58.2        41.5   

Other, net

     56.8        38.9   
  

 

 

   

 

 

 

Total Deferred Tax Liabilities

     1,223.2        1,022.9   
  

 

 

   

 

 

 

Deferred tax assets

    

Deferred investment tax credits and other regulatory liabilities

     (107.9     (133.2

Environmental liabilities

     (3.1     (7.4

Net operating loss carryforward and AMT credit carryforward

     (40.2     (0.7

Other accrued liabilities

     (4.7     (0.7
  

 

 

   

 

 

 

Total Deferred Tax Assets

     (155.9     (142.0
  

 

 

   

 

 

 

Net Deferred Tax Liabilities less Deferred Tax Assets

     1,067.3        880.9   
  

 

 

   

 

 

 

Less: Deferred income taxes related to current assets and liabilities(1)

     (9.7     (45.5
  

 

 

   

 

 

 

Non-Current Deferred Tax Liabilities

   $ 1,077.0      $ 926.4   
  

 

 

   

 

 

 

 

(1) 

Current deferred taxes are located in Prepayments and other on the Combined Balance Sheets.

The net operating loss carryforward represents a federal carryforward of $40.2 million that will expire in 2033.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

 

Reconciliation of Unrecognized Tax Benefits

   2013     2012     2011  
     (in millions)  

Unrecognized Tax Benefits—Opening Balance

   $ 4.9      $ 15.3      $ 15.2   

Gross decreases—tax positions in prior period

     (4.8     (10.4     (1.9

Gross increases—current period tax positions

     —          —          2.0   
  

 

 

   

 

 

   

 

 

 

Unrecognized Tax Benefits—Ending Balance

   $ 0.1      $ 4.9      $ 15.3   
  

 

 

   

 

 

   

 

 

 

Offset for outstanding IRS refunds

     —          (4.8     (18.9

Offset for net operating loss carryforwards

     —          —          3.6   
  

 

 

   

 

 

   

 

 

 

Balance—Net of Refunds and Net Operating Loss Carryforwards

   $ 0.1      $ 0.1      $ —     
  

 

 

   

 

 

   

 

 

 

Based upon its intent to comply with Internal Revenue Procedures, Tangible Property Regulations and the Stand-down Position audit adjustment, the Predecessor determined that the unrecognized tax benefit associated with the requested change in tax accounting method filed for 2008 related to gas transmission required a re-measurement

 

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under the provisions of ASC 740. Therefore, in 2012 the Predecessor recognized an income tax receivable of $15.6 million related to the 2008 and 2009 tax years, previously unrecognized. Except for interest recorded on the tax receivables, the recognition of the receivables did not materially affect tax expense or net income.

In 2010, the Predecessor received permission to change its method of accounting for capitalizing overhead costs. The Predecessor recorded an unrecognized tax benefit related to this uncertain tax position of $2.4 million in 2010. In 2011, this estimate was revised to $4.2 million. In 2012, the IRS completed fieldwork for the audit for the years 2008-2010, pending Joint Committee review. The Predecessor revised the unrecognized tax benefit related to this issue to incorporate 2012 activity. At December 31, 2012, the unrecognized tax benefits were $4.2 million. This issue was resolved in 2013.

Except as discussed above, there have been no other material changes in 2013 to the Predecessor’s uncertain tax positions recorded as of December 31, 2012.

The total amount of unrecognized tax benefits at December 31, 2013, 2012 and 2011 that, if recognized, would affect the effective tax rate is $0.1 million for December 31, 2013 and 2012 and zero for December 31, 2011. As of December 31, 2013, the Predecessor did not anticipate any significant changes to its liabilities for unrecognized tax benefits over the twelve months ended December 31, 2014. As of December 31, 2012, it was reasonably possible that a $4.2 million decrease in unrecorded tax benefits could occur in 2013 due primarily to Joint Committee Taxation review of the 2008-2010 federal audit. The results of the review are described above.

The Predecessor recognizes accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities, and tax penalties in income tax expense. With respect to its unrecognized tax benefits, the Predecessor recorded amounts under $0.1 million in interest expense in the Combined Statements of Operations for the years ended December 31, 2013, 2012 and 2011. For the years ended December 31, 2013, 2012 and 2011, the Predecessor reported amounts under $0.1 million, of accrued interest payable on unrecognized tax benefits on its Combined Balance Sheets. There were no accruals for penalties recorded in the Combined Statements of Operations for the years ended December 31, 2013, 2012 and 2011 and there were no balances for accrued penalties recorded on the Combined Balance Sheets as of December 31, 2013 and December 31, 2012.

The Predecessor is subject to income taxation in the United States and various state jurisdictions, primarily West Virginia, Virginia, Pennsylvania, Kentucky, Louisiana, Mississippi, Maryland, Tennessee, New Jersey and New York.

Because the Predecessor’s parent, NiSource, is part of the IRS’s Large and Mid-Size Business program, each year’s federal income tax return is typically audited by the IRS. As of December 31, 2013, tax years through 2010 have been audited and are effectively closed to further assessment, except for immaterial carryforward amounts. The audit of tax years 2011 and 2012 began in 2013, respectively. NiSource is involved in the Compliance Assurance Program for tax year 2013.

The statute of limitations in each of the state jurisdictions in which the Predecessor operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2013, there were no state income tax audits in progress that would have a material impact on the combined financial statements.

11. Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of the Predecessor. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees of the Predecessor. The majority of employees may become

 

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eligible for these benefits if they reach retirement age while working for the Predecessor. The expected cost of such benefits is accrued during the employees’ years of service. The Predecessor’s current rates charged to its customers include postretirement benefit costs. Cash contributions are remitted to grantor trusts.

The Predecessor is a participant in the consolidated NiSource defined benefit retirement plans (the Plans), and therefore, the Predecessor is allocated a ratable portion of NiSource’s grantor trusts for the Plans in which its employees and retirees participate. As a result, the Predecessor follows multiple employer accounting under the provisions of GAAP.

Pension and Other Postretirement Benefit Plans’ Asset Management. NiSource employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

NiSource utilizes a building block approach with proper consideration of diversification and rebalancing in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for the NiSource plan assets represents a long-term view and are listed in the following table below.

In 2012, a dynamic asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, real estate, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by the projected benefit obligations of the qualified pension plans divided by the market value of qualified pension plan assets). The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on December 31, 2013 are as follows:

Asset Mix Policy of Funds:

 

     Defined Benefit Pension Plan     Postretirement Benefit Plan  

Asset Category

   Minimum     Maximum     Minimum     Maximum  

Domestic Equities

     25     45     35     55

International Equities

     15     25     15     25

Fixed Income

     23     37     20     50

Real Estate/Private Equity/Hedge Funds

     0     15     0     0

Short-term Investments

     0     10     0     10

 

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Pension Plan and Postretirement Plan Asset Mix allocated to the Predecessor at December 31, 2013:

 

December 31, 2013

   Defined Benefit
Pension Plan Assets
    Postretirement Benefit
Plan Assets
 

Asset Class

   Asset Value      % of Total
Assets
    Asset Value      % of Total
Assets
 
     (in millions)            (in millions)         

Domestic Equities

   $ 120.8         40.4   $ 95.4         48.0

International Equities

     62.3         20.8     37.7         19.0

Fixed Income

     84.0         28.1     57.7         29.0

Real Estate/Private Equity/Hedge Funds

     16.8         5.6     —           0.0

Cash/Other

     15.2         5.1     8.0         4.0
  

 

 

    

 

 

   

 

 

    

 

 

 
   $ 299.1         100.0   $ 198.8         100.0
  

 

 

    

 

 

   

 

 

    

 

 

 

Pension Plan and Postretirement Plan Asset Mix allocated to the Predecessor at December 31, 2012:

 

December 31, 2012

   Defined Benefit
Pension Plan Assets
    Postretirement Benefit
Plan Assets
 

Asset Class

   Asset Value      % of Total
Assets
    Asset Value      % of Total
Assets
 
     (in millions)            (in millions)         

Domestic Equities

   $ 108.4         37.4   $ 75.2         45.3

International Equities

     60.9         21.0     32.0         19.3

Fixed Income

     89.0         30.7     58.1         35.0

Real Estate/Private Equity/Hedge Funds

     29.9         10.3     —           0.0

Cash/Other

     1.7         0.6     0.7         0.4
  

 

 

    

 

 

   

 

 

    

 

 

 
   $ 289.9         100.0   $ 166.0         100.0
  

 

 

    

 

 

   

 

 

    

 

 

 

The categorization of investments into the asset classes in the table above are based on definitions established by the NiSource Benefits Committee.

Fair Value Measurements. The following tables set forth, by level within the fair value hierarchy, the Master Trust and OPEB investment assets at fair value as of December 31, 2013 and 2012. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total Master Trust and OPEB investment assets at fair value classified within Level 3 were $16.4 million and $43.9 million as of December 31, 2013 and 2012, respectively. Such amounts were approximately 3% and 10% of the Master Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2013 and 2012, respectively.

Valuation Techniques Used to Determine Fair Value:

Level 1 Measurements

Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.

 

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Level 2 Measurements

Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.

Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are classified as Level 2. The funds’ underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments.

Level 3 Measurements

Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds’ underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods.

The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days’ notice. Private equity investment strategies include buy-out, venture capital, growth equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships.

Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership’s fair value as recorded in the partnerships’ audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation.

For the year ended December 31, 2013, there were no significant changes to valuation techniques to determine the fair value of NiSource’s pension and other postretirement benefits’ assets.

 

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The following table reflects the Predecessor’s allocation of pension and other postretirement benefit amounts:

 

Fair Value Measurements

   December 31,
2013
    Quoted Prices in
Assets (Level 1)
     Significant
Inputs (Level 2)
     Significant
Inputs (Level 3)
 
     (in millions)  

Pension plan assets:

          

Cash

   $ 1.2      $ 1.2       $ —         $ —     

Equity securities

          

U.S. equities

     43.6        43.6         —           —     

International equities

     20.5        20.3         0.2         —     

Fixed income securities

          

Government

     16.5        11.1         5.4         —     

Corporate

     21.9        —           21.9         —     

Mortgage/Asset backed securities

     8.1        —           8.1         —     

Other fixed income

     0.1        —           0.1         —     

Commingled funds

          

Short-term money markets

     10.7        —           10.7         —     

U.S. equities

     75.8        —           75.8         —     

International equities

     41.4        —           41.4         —     

Fixed income

     37.4        —           37.4         —     

Private equity limited partnerships

          

U.S. multi-strategy(a)

     7.6        —           —           7.6   

International multi-strategy(b)

     5.0        —           —           5.0   

Distressed opportunities

     1.2        —           —           1.2   

Real estate

     2.6        —           —           2.6   
  

 

 

   

 

 

    

 

 

    

 

 

 

Pension plan assets subtotal

     293.6        76.2         201.0         16.4   
  

 

 

   

 

 

    

 

 

    

 

 

 

Other postretirement benefit plan assets

          

Commingled funds

          

Short-term money markets

     8.0        —           8.0         —     

U.S. equities

     13.0        —           13.0         —     

Mutual funds

          

U.S. equities

     82.5        82.5         —           —     

International equities

     37.8        37.8         —           —     

Fixed income

     57.5        57.5         —           —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Other postretirement benefit plan assets subtotal

     198.8        177.8         21.0         —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Due to brokers, net(c)

     (1.3        

Accrued investment income/dividends

     0.5           

Net receivables(d)

     6.3           
  

 

 

   

 

 

    

 

 

    

 

 

 

Total pension and other postretirement benefit plan assets

   $ 497.9      $ 254.0       $ 222.0       $ 16.4   
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(a)

This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.

 

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(b) This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(c) This class represents pending trades with brokers.
(d) Reflects $6.2 million in December 31, 2013 hedge funds redemptions in which cash has not been received. These hedge fund investments had previously been included as level 3 investments prior to the redemptions.

 

     Balance at
January 1,
2013
     Total gains or
losses
(unrealized/
realized)
    Purchases      (Sales)     Transfers
into/(out of)
Level 3
     Balance at
December 31,
2013
 

Fixed income securities

               

Government

   $ 0.1       $ —        $ —         $ (0.1   $ —         $ —     

Commingled funds

               

Fixed income

     14.1         0.2        —           (14.3     —           —     

Hedge fund of funds

               

Multi-strategy

     7.1         —          —           (7.1     —           —     

Equities-market neutral

     4.2         0.1        —           (4.3     —           —     

Private equity limited partnerships

               

U.S. multi-strategy

     8.4         (0.1     0.5         (1.2     —           7.6   

International multi-strategy

     5.8         (0.3     0.1         (0.6     —           5.0   

Distressed opportunities

     1.5         0.1        —           (0.4     —           1.2   

Real estate

     2.7         0.2        —           (0.3     —           2.6   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 43.9       $ 0.2      $ 0.6       $ (28.3   $ —         $ 16.4   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

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The following table reflects the Predecessor’s allocation of pension and other postretirement benefit amounts:

 

Fair Value Measurements

   December 31,
2012
    Quoted Prices in
Assets (Level 1)
     Significant
Inputs (Level 2)
     Significant
Inputs (Level 3)
 
     (in millions)  

Pension plan assets:

          

Cash

   $ 0.8      $ 0.8       $ —         $ —     

Equity securities

          

U.S. equities

     71.2        70.9         0.3         —     

International equities

     19.8        19.6         0.2         —     

Fixed income securities

          

Government

     23.2        16.1         7.0         0.1   

Corporate

     14.1        —           14.1         —     

Mortgages/Asset backed securities

     14.6        —           14.6         —     

Other fixed income

     0.1        —           0.1         —     

Commingled funds

          

Short-term money markets

     8.0        —           8.0         —     

U.S. equities

     31.2        —           31.2         —     

International equities

     40.1        —           40.1         —     

Fixed income

     38.0        —           23.9         14.1   

Hedge fund of funds

          

Multi-strategy(a)

     7.1        —           —           7.1   

Equities-market neutral(b)

     4.2        —           —           4.2   

Private equity limited partnerships

          

U.S. multi-strategy(c)

     8.4        —           —           8.4   

International multi-strategy(d)

     5.8        —           —           5.8   

Distressed opportunities

     1.5        —           —           1.5   

Real estate

     2.7        —           —           2.7   
  

 

 

   

 

 

    

 

 

    

 

 

 

Pension plan assets subtotal

     290.8        107.4         139.5         43.9   
  

 

 

   

 

 

    

 

 

    

 

 

 

Other postretirement benefit plan assets

          

Commingled funds

          

Short-term money markets

     0.3        —           0.3         —     

U.S. equities

     10.4        —           10.4         —     

Mutual funds

          

U.S. equities

     64.5        64.5         —           —     

International equities

     32.7        32.7         —           —     

Fixed income

     58.1        58.1         —           —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Other postretirement benefit plan assets subtotal

     166.0        155.3         10.7         —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Due to brokers, net(e)

     (1.4        

Accrued investment income/dividends

     0.5           

Net receivables

     —             
  

 

 

   

 

 

    

 

 

    

 

 

 

Total pension and other postretirement benefit plan assets

   $ 455.9      $ 262.7       $ 150.2       $ 43.9   
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(a) This class includes hedge fund of funds that invest in a diverse portfolio of strategies including relative value, event driven and long/short equities.
(b) This class includes hedge fund of funds that invest in long/short equities, which in total maintain a relatively net market neutral position.
(c)

This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.

 

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(d) This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.
(e) This class represents pending trades with brokers.

 

    Balance at
January 1,
2012
    Total gains or
losses
(unrealized/
realized)
    Purchases     (Sales)     Transfers
into/(out of)
Level 3
    Balance at
December 31,
2013
 

Fixed income securities

           

Government

  $ 0.1      $ —        $ —        $ —        $ —        $ 0.1   

Mortgages /Asset backed securities

    0.2        —          —          —          (0.2     —     

Commingled funds

           

Fixed income

    14.4        0.9        0.5        (1.7     —          14.1   

Hedge fund of funds

           

Multi-strategy

    6.7        0.4        —          —          —          7.1   

Equities-market neutral

    4.5        (0.3     —          —          —          4.2   

Private equity limited partnerships

           

U.S. multi-strategy

    8.3        (0.3     1.3        (0.9     —          8.4   

International multi-strategy

    5.8        (0.5     0.7        (0.2     —          5.8   

Distressed opportunities

    1.7        (0.1     0.1        (0.2     —          1.5   

Real estate

    2.9        0.2        —          (0.4     —          2.7   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 44.6      $ 0.3      $ 2.6      $ (3.4   $ (0.2   $ 43.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

As noted above, the Predecessor follows multiple employer accounting under the provisions of GAAP, and, therefore, is allocated a ratable portion of the NiSource’s grantor trusts for the plans in which its employees and retirees participate. The allocation of the fair value of assets is based upon the ratable share of plan funding and participant benefit payments. Investment activity within the trust occurs at the trust level, and the Predecessor is allocated a portion of investment gains and losses based on its percentage of the total NiSource projected benefit obligation. For the year ended December 31, 2013, NiSource had purchases, sales and transfers into (out of) Level 3 assets of $4.7 million, $(208.7) million, and $(0.2) million, respectively. The net realized and unrealized gain on Level 3 assets was $2.2 million. The Predecessor’s allocation of the activity in 2013 was 13.2%.

For the year ended December 31, 2012, NiSource had purchases, sales and transfers into (out of) Level 3 assets of $19.3 million, $(22.7) million, and $(1.2) million, respectively. The net realized and unrealized gain on Level 3 assets was $4.5 million. The Predecessor’s allocation of the activity in 2012 was 13.4%.

 

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Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure. The following table provides a reconciliation of the plans’ funded status and amounts reflected in the Predecessor’s balance sheet at December 31 based on a December 31 measurement date:

 

     Pension Benefits             Other Postretirement Benefits           
     2013     2012     2013     2012  
     (in millions)  

Change in projected benefit obligation(a)

        

Benefit obligation at beginning of year

   $ 372.5      $ 330.3      $ 128.8      $ 126.5   

Service cost

     4.8        5.9        1.5        1.5   

Interest cost

     12.6        14.6        4.9        5.9   

Plan participants’ contributions

     —          —          1.8        1.8   

Plan amendments

     —          —          0.1        (1.5

Settlement gain

     2.6        —          —          —     

Actuarial loss (gain)

     (22.8     49.3        (22.2     4.0   

Benefits paid

     (42.6     (27.6     (9.6     (9.6

Estimated benefits paid by incurred subsidiary

     —          —          0.2        0.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Projected benefit obligation at end of year

   $ 327.1      $ 372.5      $ 105.5      $ 128.8   

Change in plan assets

        

Fair value of plan assets at beginning of year

   $ 289.9      $ 285.6      $ 166.0      $ 142.7   

Actual return on plan assets

     39.9        31.9        30.0        20.3   

Employer contributions

     11.9        —          10.6        10.8   

Plan participants’ contributions

     —          —          1.8        1.8   

Benefits paid

     (42.6     (27.6     (9.6     (9.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of year

   $ 299.1      $ 289.9      $ 198.8      $ 166.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Funded status at end of year

   $ (28.0   $ (82.6   $ 93.3      $ 37.2   
  

 

 

   

 

 

   

 

 

   

 

 

 
        

Amounts recognized in the balance sheet consist of:

        

Noncurrent assets

   $ —        $ —        $ 100.9      $ 51.1   

Current liabilities

     —          —          —          —     

Noncurrent liabilities

     (28.0     (82.6     (7.6     (13.9
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount recognized at end of year(b)

   $ (28.0     (82.6   $ 93.3      $ 37.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized as regulatory assets/liabilities(c)

        

Unrecognized transition asset obligation

   $ —        $ —        $ —        $ —     

Unrecognized prior service (credit) cost

     (5.0     (5.9     0.2        —     

Unrecognized actuarial (gain) loss

     106.9        168.1        (20.2     19.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized regulatory assets (liabilities)

   $ 101.9      $ 162.2      $ (20.0   $ 19.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.
(b) The Predecessor recognizes in its balance sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(c) The Predecessor determined that the future recovery of pension and other postretirement benefits costs is probable. The Predecessor recorded regulatory assets and liabilities of $101.9 million and $20.0 million, respectively, as of December 31, 2013 and $182.3 million and $0.4 respectively, as of December 31, 2012, that would otherwise have been recorded to accumulated other comprehensive loss.

 

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The Predecessor’s accumulated benefit obligation for its pension plans was $327.1 million and $372.5 million as of December 31, 2013 and 2012, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels.

The Predecessor’s pension plans were underfunded by $28.0 million at December 31, 2013 compared to being underfunded at December 31, 2012 by $82.6 million. The improvement in the funded status was due primarily to favorable asset returns, an increase in discount rate from the prior measurement date and increased employer contributions. The Predecessor contributed $11.9 million to its pension plans in 2013. No contributions were made to the pension plans in 2012.

The Predecessor’s funded status for its other postretirement benefit plans improved by $56.1 million to an overfunded status of $93.3 million primarily due to favorable asset returns, an increase in discount rate from the prior measurement date and a change in the retirement rate assumption. No amounts of the Predecessor’s pension or other postretirement plans’ assets are expected to be returned to the Predecessor in 2014.

In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plan’s 2013 service cost plus interest cost and, therefore, settlement accounting was required. As a result, the Predecessor recorded a settlement charge of $12.4 million in 2013. The Predecessor’s net periodic pension benefit cost for 2013 was decreased by $1.2 million as a result of the interim remeasurements.

The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for the Predecessor’s various plans as of December 31.

 

     Pension Benefits     Other Postretirement Benefits  
         2013             2012             2013             2012      

Weighted-average assumptions to determine benefit obligation

        

Discount Rate

     4.34     3.36     4.74     3.92

Rate of Compensation Increases

     4.00     4.00     —          —     

Health Care Trend Rates

        

Trend for Next Year

     —          —          7.09     7.25

Ultimate Trend

     —          —          4.50     5.00

Year Ultimate Trend Reached

     —          —          2021        2018   

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

     1% point
increase
     1% point
decrease
 
     (in millions)  

Effect on service and interest components of net periodic cost

   $ 0.2       $ (0.2

Effect on accumulated postretirement benefit obligation

     3.3         (2.9

The Predecessor does not expect to make any material contributions to its pension plans in 2014. Contributions of approximately $10.0 million are expected to be made to its postretirement medical and life plans in 2014.

 

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The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure the Predecessor’s benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees.

 

     Pension
Benefits
     Postretirement
Benefits
     Other Federal
Subsidiary
Receipts
 
     (in millions)  

Year(s)

        

2014

   $ 25.4       $ 8.8       $ 0.4   

2015

     25.4         8.3         0.5   

2016

     27.7         8.1         0.5   

2017

     27.8         7.8         0.5   

2018

     28.9         7.9         0.6   

2019-2023

     151.0         38.5         2.5   

The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended December 31, 2013, 2012, and 2011:

 

    Pension Benefits     Other Postretirement Benefits  
        2013             2012             2011             2013             2012             2011      
    (in millions)  

Components of net periodic benefit

           

Cost (Income)

           

Service cost

  $ 4.8      $ 5.9      $ 6.0      $ 1.5      $ 1.5      $ 1.5   

Interest cost

    12.6        14.6        16.0        4.9        5.9        6.7   

Expected return on assets

    (22.0     (22.6     (22.7     (13.5     (11.6     (11.5

Amortization of prior service (credit) cost

    (0.9     (0.9     (0.9     0.1        0.3        0.2   

Recognized actuarial loss

    10.6        11.0        6.8        1.0        0.7        0.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Periodic Benefit Cost (Income)

  $ 5.1      $ 8.0      $ 5.2      $ (6.0   $ (3.2   $ (3.0

Settlement loss

    12.4        —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Net Periodic Benefit Cost (Income)

  $ 17.5      $ 8.0      $ 5.2      $ (6.0   $ (3.2   $ (3.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The actuarially-determined pension benefit cost was $17.5 million in 2013 and $8.0 million in 2012. This increase is due primarily to the settlement loss in 2013 and decreasing interest rates, partially offset by favorable asset returns. The actuarially-determined other post-retirement benefit plan income was $6.0 million in 2013 and $3.2 million in 2012.

The following table provides the key assumptions that were used to calculate the net periodic benefits cost for the Predecessor’s various plans.

 

    Pension Benefits     Other Postretirement Benefits  
        2013             2012             2011             2013             2012             2011      

Weighted-average assumptions to determine net periodic benefit cost

           

Discount Rate

    3.36     4.60     5.00     3.92     4.88     5.29

Expected Long-Term Rate of Return on Plan Assets

    8.30     8.30     8.75     8.15     8.17     8.26

Rate of Compensation Increases

    4.00     4.00     4.00     —          —          —     

The Predecessor believes it is appropriate to assume an 8.30% rate of return on pension plan assets for its calculation of 2013 pension benefits cost. This is primarily based on asset mix and historical rates of return.

 

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The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability.

 

    Pension Benefits     Other Postretirement Benefits  
        2013             2012             2013             2012      
    (in millions)  

Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities

       

Net prior service cost/(credit)

  $ —        $ —        $ 0.2      $ (1.6

Net actuarial (gain)/loss

    (38.2     39.9        (38.8     (4.7

Less: Settlement loss

    (12.4     —          —          —     

Less: amortization of prior service cost

    0.9        0.9        (0.1     (0.3

Less: amortization of net actuarial gain

    (10.6     (11.0     (1.0     (0.7
 

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in regulatory assets/liabilities

  $ (60.3   $ 29.8      $ (39.7   $ (7.3
 

 

 

   

 

 

   

 

 

   

 

 

 

Amount recognized in net periodic benefit cost and regulatory assets/liabilities

  $ (42.8   $ 37.8      $ (45.7   $ (10.3
 

 

 

   

 

 

   

 

 

   

 

 

 

Based on a December 31 measurement date, the net unrecognized actuarial loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2014 for the pension plans are $6.5 million, $(1.0) million and zero, respectively, and for other postretirement benefit plans are zero, $0.1 million and zero, respectively.

12. Fair Value

The Predecessor has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits and short-term borrowings—affiliated. The Predecessor’s long-term debt—affiliated are recorded at historical amounts.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Long-term debt—affiliated. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2013 and 2012, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

The carrying amount and estimated fair values of financial instruments were as follows:

 

     At December 31,  
     Carrying
Amount 2013
     Estimated Fair
Value 2013
     Carrying
Amount 2012
     Estimated Fair
Value 2012
 
     (in millions)  

Long-term debt—affiliated

   $ 819.8       $ 835.7       $ 754.7       $ 828.9   

13. Other Commitments and Contingencies

A. Other Legal Proceedings. In the normal course of its business, the Predecessor has been named as a defendant in various legal proceedings. In the opinion of the Predecessor, the ultimate disposition of these currently asserted claims will not have a material impact on the Predecessor’s combined financial statements.

 

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B. Tax Matters. The Predecessor records liabilities for potential income tax assessments. The accruals relate to tax positions in a variety of taxing jurisdictions and are based on the Predecessor’s estimate of the ultimate resolution of these positions. These liabilities may be affected by changing interpretations of laws, rulings by tax authorities, or the expiration of the statute of limitations. The Predecessor’s parent, NiSource, is part of the IRS Large and Mid-Size Business program. As a result, each year’s federal income tax return is typically audited by the IRS. As of December 31, 2013, tax years through 2010 have been audited and are effectively closed to further assessment. The audits of tax years 2011, 2012 and 2013 under the Compliance Assurance Program (“CAP”) are in process. As of December 31, 2013, there were no state income tax audits in progress that would have a material impact on the combined financial statements.

The Predecessor is currently being audited for sales and use tax compliance in the state of Louisiana.

C. Environmental Matters. The Predecessor operations are subject to environmental statutes and regulations related to water quality, hazardous waste and solid waste. The Predecessor believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.

It is the Predecessor’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. The Predecessor expects a significant portion of environmental assessment and remediation costs to be recoverable through rates.

As of December 31, 2013 and 2012, the Predecessor recorded an accrual of approximately $8.8 million and $21.7 million, respectively, to cover environmental remediation at various sites. The current portion of this accrual is included in “Legal and environmental” in the Combined Balance Sheets. The noncurrent portion is included in Other noncurrent liabilities in the Combined Balance Sheets. The Predecessor accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. These expenditures are not currently estimable at some sites. The Predecessor periodically adjusts its accrual as information is collected and estimates become more refined.

Waste

The Predecessor continues to conduct characterization and remediation activities at specific sites under a 1995 AOC (subsequently modified in 1996 and 2007). The 1995 AOC originally covered 245 major facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations and about 3,700 storage well locations. As a result of the 2007 amendment, approximately 50 facilities remain subject to the terms of the AOC. The Predecessor utilizes a probabilistic model to estimate its future remediation costs related to the 1995 AOC. The model was prepared with the assistance of a third party and incorporates the Predecessor and general industry experience with remediating sites. The Predecessor completes an annual refresh of the model in the second quarter of each fiscal year. No material changes to the liability were noted as a result of the refresh completed as of June 30, 2013. The total liability at the Predecessor related to the facilities subject to remediation was $8.7 million and $21.7 million at December 31, 2013 and December 31, 2012, respectively. The liability represents the Predecessor’s best estimate of the cost to remediate the facilities or manage the sites. Remediation costs are estimated based on the information available, applicable remediation standards, and experience with similar facilities. The Predecessor expects that the remediation for these facilities will be substantially completed in 2015. Refer to Note 8 “Regulatory Matters” in the Notes to Combined Financial Statements for information regarding recoverability.

 

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D. Operating Lease Commitments. The Predecessor leases assets in several areas of its operations. Payments made in connection with operating leases were $13.4 million in 2013, $10.7 million in 2012 and $11.4 million in 2011, and are primarily charged to operation and maintenance expense as incurred.

Future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are:

 

     Operating
Leases
 
     (in millions)  

2014

   $ 4.2   

2015

     2.6   

2016

     2.3   

2017

     2.1   

2018

     1.8   

After

     4.7   
  

 

 

 

Total future minimum payments

   $ 17.7   
  

 

 

 

E. Service Obligations. The Predecessor has entered into various service agreements whereby the Predecessor is contractually obligated to make certain minimum payments in future periods. The Predecessor has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2014 to 2024, require the Predecessor to pay fixed monthly charges.

The estimated aggregate amounts of minimum fixed payments at December 31, 2013, were:

 

     Pipeline Service
Agreements
 
     (in millions)  

2014

   $ 37.6   

2015

     36.0   

2016

     31.0   

2017

     21.4   

2018

     17.9   

After

     55.6   
  

 

 

 

Total future minimum payments

   $ 199.5   
  

 

 

 

 

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14. Accumulated Other Comprehensive Loss

The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

 

     Gains and Losses
on Cash Flow
Hedges(1)
    Pension and
OPEB  Items(1)
    Accumulated
Other
Comprehensive
Loss(1)
 
     (in millions)  

Balance as of January 1, 2011

   $ (21.1   $ —        $ (21.1
  

 

 

   

 

 

   

 

 

 

Other comprehensive income before reclassifications

     —          —          —     

Amounts reclassified from accumulated other comprehensive income

     1.4        —          1.4   
  

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     1.4        —          1.4   
  

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2011

   $ (19.7   $ —        $ (19.7
  

 

 

   

 

 

   

 

 

 

Other comprehensive income before reclassifications

     —          —          —     

Amounts reclassified from accumulated other comprehensive income

     1.0        (0.1     0.9   
  

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     1.0        (0.1     0.9   

Balance as of December 31, 2012

   $ (18.7   $ (0.1   $ (18.8
  

 

 

   

 

 

   

 

 

 

Other comprehensive income before reclassifications

     —          —          —     

Amounts reclassified from accumulated other comprehensive income

     1.1        —          1.1   
  

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     1.1        —          1.1   
  

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2013

   $ (17.6   $ (0.1   $ (17.7
  

 

 

   

 

 

   

 

 

 

 

(1) 

All amounts are net of tax. Amounts in parentheses indicate debits.

Equity Method Investment

During 2008, Millennium Pipeline, in which the Predecessor has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties. During August 2010, Millennium Pipeline completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million, $375.0 million at 5.33% due June 30, 2027 and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium Pipeline repaid all outstanding borrowings under its credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were primarily accounted for as cash flow hedges by Millennium Pipeline. As an equity method investment, the Predecessor is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining proportional share of unrecognized loss of $17.6 million, net of tax, related to these terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $17.6 million and $18.7 million at December 31, 2013 and December 31, 2012, respectively, is included in unrealized losses on cash flow hedges above.

 

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15. Other, Net

 

     Year Ended December 31,  
       2013          2012          2011    
     (in millions)  

AFUDC Equity

   $ 6.8       $ 1.4       $ —     

Miscellaneous(1)

     10.8         0.1         1.2   
  

 

 

    

 

 

    

 

 

 

Total Other, net

   $ 17.6       $ 1.5       $ 1.2   
  

 

 

    

 

 

    

 

 

 

 

(1) 

Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

16. Segments of Business

Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The NiSource Chief Executive Officer is the chief operating decision maker.

At December 31, 2013, the Predecessor’s operations comprise one operating segment. The Predecessor’s segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services and development of mineral rights positions.

17. Supplemental Cash Flow Information

The following table provides additional information regarding the Predecessor’s Combined Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011:

 

     Year Ended December 31,  
       2013            2012          2011    
     (in millions)  

Supplemental Disclosures of Cash Flow Information

        

Non-cash transactions:

        

Capital expenditures included in current liabilities

   $ 53.1       $ 77.2       $ 35.2   

Schedule of interest and income taxes paid:

        

Cash paid for interest, net of interest capitalized amounts

   $ 39.5       $ 32.4       $ 32.6   

Cash paid for income taxes

     10.2         81.7         18.1   

18. Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party, accounted for greater than 10% of total operating revenues in the year ended December 31, 2013, 2012 and 2011. Washington Gas and Light, a non-affiliated entity, accounted for greater than 10% of total operating revenues in the year ended December 31, 2012 and 2011. The following table provides the customer operating revenues and the customer operating revenues as a percentage of total operating revenues for the years ended December 31, 2013, 2012 and 2011:

 

     2013     2012     2011  
     Total
Operating
Revenues
     Percentage of
Total
Operating
Revenues
    Total
Operating
Revenues
     Percentage of
Total
Operating
Revenues
    Total
Operating
Revenues
     Percentage of
Total
Operating
Revenues
 
     (in millions)  

Columbia Gas of Ohio

   $ 167.5         14.2   $ 172.4         17.2   $ 173.3         17.2

Washington Gas and Light

     104.6         8.9     107.1         10.7     108.1         10.7

There was no other single customer that accounted for greater than ten percent of total operating revenues during 2013, 2012 or 2011. The loss of a significant portion of operating revenues from either of these customers would have a material adverse effect on the business of the Predecessor.

 

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Table of Contents

Appendix A

 

 

 

 

FORM OF

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

COLUMBIA PIPELINE PARTNERS LP

 

 

 

 


Table of Contents

TABLE OF CONTENTS

 

ARTICLE I   
DEFINITIONS   

Section 1.1

  

Definitions

     A-1   

Section 1.2

  

Construction

     A-20   
ARTICLE II   
ORGANIZATION   

Section 2.1

  

Formation

     A-20   

Section 2.2

  

Name

     A-20   

Section 2.3

  

Registered Office; Registered Agent; Principal Office; Other Offices

     A-20   

Section 2.4

  

Purpose and Business

     A-20   

Section 2.5

  

Powers

     A-21   

Section 2.6

  

Term

     A-21   

Section 2.7

  

Title to Partnership Assets

     A-21   
ARTICLE III   
RIGHTS OF LIMITED PARTNERS   

Section 3.1

  

Limitation of Liability

     A-21   

Section 3.2

  

Management of Business

     A-21   

Section 3.3

  

Outside Activities of the Limited Partners

     A-22   

Section 3.4

  

Rights of Limited Partners

     A-22   
ARTICLE IV   
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS    

Section 4.1

  

Certificates

     A-23   

Section 4.2

  

Mutilated, Destroyed, Lost or Stolen Certificates

     A-23   

Section 4.3

  

Record Holders

     A-24   

Section 4.4

  

Transfer Generally

     A-24   

Section 4.5

  

Registration and Transfer of Limited Partner Interests

     A-24   

Section 4.6

  

Transfer of the General Partner’s General Partner Interest

     A-25   

Section 4.7

  

Restrictions on Transfers

     A-25   

Section 4.8

  

Eligibility Certificates; Ineligible Holders

     A-26   

Section 4.9

  

Redemption of Partnership Interests of Ineligible Holders

     A-27   
ARTICLE V   
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS   

Section 5.1

  

Organizational Contributions

     A-28   

Section 5.2

  

Contributions by the General Partner and its Affiliates

     A-28   

Section 5.3

  

Contributions by Initial Limited Partners

     A-28   

Section 5.4

  

Interest and Withdrawal

     A-28   

Section 5.5

  

Capital Accounts

     A-29   

Section 5.6

  

Issuances of Additional Partnership Interests and Derivative Instruments

     A-31   

Section 5.7

  

Conversion of Subordinated Units

     A-32   

Section 5.8

  

Limited Preemptive Right

     A-32   

 

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Table of Contents

Section 5.9

  

Splits and Combinations

     A-32   

Section 5.10

  

Fully Paid and Non-Assessable Nature of Limited Partner Interests

     A-33   

Section 5.11

  

Issuance of Common Units in Connection with Reset of Incentive Distribution Rights

     A-33   

Section 5.12

  

Deemed Capital Contributions

     A-35   
ARTICLE VI   
ALLOCATIONS AND DISTRIBUTIONS   

Section 6.1

  

Allocations for Capital Account Purposes

     A-35   

Section 6.2

  

Allocations for Tax Purposes

     A-44   

Section 6.3

  

Distributions; Characterization of Distributions; Distributions to Record Holders

     A-46   

Section 6.4

  

Distributions from Operating Surplus

     A-46   

Section 6.5

  

Distributions from Capital Surplus

     A-47   

Section 6.6

  

Adjustment of Target Distribution Levels

     A-48   

Section 6.7

  

Special Provisions Relating to the Holders of Subordinated Units

     A-48   

Section 6.8

  

Special Provisions Relating to the Holders of IDR Reset Common Units

     A-49   

Section 6.9

  

Entity-Level Taxation

     A-49   
ARTICLE VII   
MANAGEMENT AND OPERATION OF BUSINESS   

Section 7.1

  

Management

     A-49   

Section 7.2

  

Replacement of Fiduciary Duties

     A-51   

Section 7.3

  

Certificate of Limited Partnership

     A-51   

Section 7.4

  

Restrictions on the General Partner’s Authority

     A-52   

Section 7.5

  

Reimbursement of the General Partner

     A-52   

Section 7.6

  

Outside Activities

     A-53   

Section 7.7

  

Indemnification

     A-53   

Section 7.8

  

Limitation of Liability of Indemnitees

     A-55   

Section 7.9

  

Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties

     A-56   

Section 7.10

  

Other Matters Concerning the General Partner

     A-57   

Section 7.11

  

Purchase or Sale of Partnership Interests

     A-58   

Section 7.12

  

Registration Rights of the General Partner and its Affiliates

     A-58   

Section 7.13

  

Reliance by Third Parties

     A-60   
ARTICLE VIII   
BOOKS, RECORDS, ACCOUNTING AND REPORTS   

Section 8.1

  

Records and Accounting

     A-60   

Section 8.2

  

Fiscal Year

     A-60   

Section 8.3

  

Reports

     A-60   
ARTICLE IX   
TAX MATTERS   

Section 9.1

  

Tax Returns and Information

     A-61   

Section 9.2

  

Tax Elections

     A-61   

Section 9.3

  

Tax Controversies

     A-62   

Section 9.4

  

Withholding; Tax Payments

     A-62   

 

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Table of Contents
ARTICLE X   
ADMISSION OF PARTNERS   

Section 10.1

  

Admission of Limited Partners

     A-62   

Section 10.2

  

Admission of Successor General Partner

     A-63   

Section 10.3

  

Amendment of Agreement and Certificate of Limited Partnership

     A-63   
ARTICLE XI   
WITHDRAWAL OR REMOVAL OF PARTNERS   

Section 11.1

  

Withdrawal of the General Partner

     A-63   

Section 11.2

  

Removal of the General Partner

     A-65   

Section 11.3

  

Interest of Departing General Partner and Successor General Partner

     A-65   

Section 11.4

  

Conversion of Subordinated Units

     A-66   

Section 11.5

  

Withdrawal of Limited Partners

     A-67   
ARTICLE XII   
DISSOLUTION AND LIQUIDATION   

Section 12.1

  

Dissolution

     A-67   

Section 12.2

  

Continuation of the Business of the Partnership After Dissolution

     A-67   

Section 12.3

  

Liquidator

     A-68   

Section 12.4

  

Liquidation

     A-68   

Section 12.5

  

Cancellation of Certificate of Limited Partnership

     A-69   

Section 12.6

  

Return of Contributions

     A-69   

Section 12.7

  

Waiver of Partition

     A-69   

Section 12.8

  

Capital Account Restoration

     A-69   
ARTICLE XIII   
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE   

Section 13.1

  

Amendments to be Adopted Solely by the General Partner

     A-69   

Section 13.2

  

Amendment Procedures

     A-70   

Section 13.3

  

Amendment Requirements

     A-71   

Section 13.4

  

Special Meetings

     A-71   

Section 13.5

  

Notice of a Meeting

     A-72   

Section 13.6

  

Record Date

     A-72   

Section 13.7

  

Postponement and Adjournment

     A-72   

Section 13.8

  

Waiver of Notice; Approval of Meeting; Approval of Minutes

     A-73   

Section 13.9

  

Quorum and Voting

     A-73   

Section 13.10

  

Conduct of a Meeting

     A-73   

Section 13.11

  

Action Without a Meeting

     A-73   

Section 13.12

  

Right to Vote and Related Matters

     A-74   

Section 13.13

  

Voting of Incentive Distribution Rights

     A-74   
ARTICLE XIV   
MERGER OR CONSOLIDATION   

Section 14.1

  

Authority

     A-75   

Section 14.2

  

Procedure for Merger or Consolidation

     A-75   

Section 14.3

  

Approval by Limited Partners

     A-76   

Section 14.4

  

Certificate of Merger

     A-77   

Section 14.5

  

Effect of Merger or Consolidation

     A-77   

 

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Table of Contents
ARTICLE XV   
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS   

Section 15.1

  

Right to Acquire Limited Partner Interests

     A-78   
ARTICLE XVI   
GENERAL PROVISIONS   

Section 16.1

  

Addresses and Notices; Written Communications

     A-79   

Section 16.2

  

Further Action

     A-79   

Section 16.3

  

Binding Effect

     A-80   

Section 16.4

  

Integration

     A-80   

Section 16.5

  

Creditors

     A-80   

Section 16.6

  

Waiver

     A-80   

Section 16.7

  

Third-Party Beneficiaries

     A-80   

Section 16.8

  

Counterparts

     A-80   

Section 16.9

   Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees      A-80   

Section 16.10

  

Invalidity of Provisions

     A-81   

Section 16.11

  

Consent of Partners

     A-81   

Section 16.12

  

Facsimile Signatures

     A-81   

 

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Table of Contents

FIRST AMENDED AND RESTATED AGREEMENT

OF LIMITED PARTNERSHIP OF COLUMBIA PIPELINE PARTNERS LP

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF COLUMBIA PIPELINE PARTNERS LP dated as of                     , 2015, is entered into by and between CPP GP LLC, a Delaware limited liability company, as the General Partner, and Columbia Energy Group, a Delaware corporation, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

Additional Book Basis” means, with respect to any Adjusted Property, the portion of the Carrying Value of such Adjusted Property that is attributable to positive adjustments made to such Carrying Value, as determined in accordance with the provisions set forth below in this definition of Additional Book Basis. For purposes of determining the extent to which Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event (an “Additional Book Basis Reduction”) and the Carrying Value of other property is increased as a result of such Book-Down Event (a “Carrying Value Increase”), then any such Carrying Value Increase shall be treated as Additional Book Basis in an amount equal to the lesser of (i) the amount of such Carrying Value Increase and (ii) the amount determined by proportionately allocating to the Carrying Value Increases resulting from such Book-Down Event the lesser of (A) the aggregate Additional Book Basis Reductions resulting from such Book-Down Event and (B) the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceed the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property; provided that the provisions of the immediately preceding sentence shall apply to the determination of the Additional Book Basis Derivative Items attributable to Disposed of Adjusted Property.

 

COLUMBIA PIPELINE PARTNERS LP

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

 

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Table of Contents

Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership, after giving effect to the following adjustments:

(a) Credit to such Capital Account any amounts which such Partner is (i) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (ii) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(b) Debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period; (b) less (i) the amount of any net increase during such period in Working Capital Borrowings (or the Partnership’s proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned); and (ii) the amount of any net decrease during such period in cash reserves (or the Partnership’s proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures not relating to an Operating Expenditure made during such period; and (c) plus (i) the amount of any net decrease during such period in Working Capital Borrowings (or the Partnership’s proportionate share of any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned); (ii) the amount of any net increase during such period in cash reserves (or the Partnership’s proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures required by any debt instrument for the repayment of principal, interest or premium; and (iii) the amount of any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established during such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus. To the extent that disbursements made, cash received or cash reserves established, increased or reduced after the end of a period are included in the determination of Operating Surplus for such period (as contemplated by the proviso in the definition of “Operating Surplus”) such disbursements, cash receipts and changes in cash reserves shall be deemed to have occurred in such period (and not in any future period) for purposes of calculating increases or decreases in Working Capital Borrowings or cash reserves during such period.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d).

Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

Affiliate Retained Units” means Units held by the Organizational Limited Partner or any Affiliate of the Organizational Limited Partner.

 

COLUMBIA PIPELINE PARTNERS LP

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

 

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Table of Contents

Aggregate Quantity of IDR Reset Common Units” is defined in Section 5.11(a).

Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

Agreed Value” of (a) a Contributed Property means the fair market value of such Contributed Property at the time of contribution and (b) an Adjusted Property means the fair market value of such Adjusted Property on the date of the Revaluation Event, in each case as determined by the General Partner.

Agreement” means this First Amended and Restated Agreement of Limited Partnership of Columbia Pipeline Partners LP, as it may be amended, supplemented or restated from time to time.

Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

Bad Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such Person, board or committee reached such determination, or engaged in or failed to engage in such act or omission, with the belief that such determination, action or omission was adverse to the interest of the Partnership.

Board of Directors” means the board of directors of the General Partner.

Book Basis Derivative Items” means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

Book-Down Event” means a Revaluation Event that gives rise to a Revaluation Loss.

Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

Book-Up Event” means a Revaluation Event that gives rise to a Revaluation Gain.

Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the U.S. or the State of Texas shall not be regarded as a Business Day.

 

COLUMBIA PIPELINE PARTNERS LP

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

 

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Table of Contents

Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

Capital Contribution” means (a) any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions) or (b) current distributions that a Partner is entitled to receive but otherwise waives.

Capital Improvement” means any (a) addition or improvement to the assets owned by any Group Member, (b) acquisition (through an asset acquisition, merger, stock acquisition, entity acquisition or other form of investment) of existing, or the construction or development of new, assets by any Group Member, or (c) capital contribution by a Group Member to a Person that is not a Subsidiary of a Group Member, in which a Group Member has, or after such capital contribution will have, an equity interest to fund the Group Member’s pro rata share of the cost of the acquisition of existing, or the construction or development of new or the replacement, improvement or expansion of existing, assets, in each case if such addition, improvement, acquisition, construction, development, replacement, improvement or expansion is made to increase the long-term operating capacity or net income of the Partnership Group from the long-term operating capacity or net income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from that existing immediately prior to such addition, improvement, acquisition, construction, development, replacement or expansion.

Capital Surplus” means cash and cash equivalents distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(b).

Carrying Value” means (a) with respect to a Contributed Property or an Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and other cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner is liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

Certificate” means a certificate in such form (including in global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.3, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

Citizenship Eligibility Trigger” is defined in Section 4.8(a)(ii).

claim” (as used in Section 7.12(c)) is defined in Section 7.12(c).

 

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FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

 

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Table of Contents

Closing Date” means the first date on which Common Units are issued and delivered by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

Code” means the U.S. Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

Columbia OpCo” means Columbia OpCo LP, a Delaware limited partnership.

Combined Interest” is defined in Section 11.3(a).

Commences Commercial Service” means a Capital Improvement or replacement asset is first put into commercial service by a Group Member (or other Person that is not a Subsidiary of a Group Member, as contemplated in the definition of “Capital Improvement”) following, if applicable, completion of construction, acquisition, development and testing.

Commission” means the U.S. Securities and Exchange Commission.

Common Unit” means a Partnership Interest having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not refer to or include any Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, with respect to any Quarter wholly within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all cash and cash equivalents distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

Conflicts Committee” means a committee of the Board of Directors composed entirely of two or more directors, each of whom is determined by the Board of Directors, after reasonable inquiry, (a) to not be an officer or employee of the General Partner (b) to not be an officer or employee of any Affiliate of the General Partner or a director of any Affiliate of the General Partner (other than any Group Member), (c) to not be a holder of any ownership interest in the General Partner or any of its Affiliates, including any Group Member, that would be likely to have an adverse impact on the ability of such director to act in an independent manner with respect to the matter submitted to the Conflicts Committee, other than Common Units and awards that are granted to such director under the LTIP, and (d) to be independent under the independence standards for directors who serve on

 

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an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

Construction Debt” means debt incurred to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on other Construction Debt or (c) distributions paid in respect of Construction Equity, and incremental Incentive Distributions in respect thereof.

Construction Equity” means equity issued to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on Construction Debt or (c) distributions paid in respect of Construction Equity, and incremental Incentive Distributions in respect thereof. Construction Equity does not include equity issued in the Initial Offering.

Construction Period” means the period beginning on the date that a Group Member (or other Person that is not a Subsidiary of a Group Member, as contemplated in the definition of “Capital Improvement”) enters into a binding obligation to commence a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that the Group Member (or other Person that is not a Subsidiary of a Group Member, as contemplated in the definition of “Capital Improvement”) abandons or disposes of such Capital Improvement.

Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property or other asset shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of                     , 2015, by and among the Partnership, NiSource Inc., NiSource Finance Corp., CPG, Columbia Energy Group, Columbia Gas Transmission Company, LLC, Columbia Gulf Transmission Company, LLC, Columbia Hardy Holdings, LLC, Columbia Hardy Corporation, the General Partner, Columbia OpCo and CPG OpCo GP LLC, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

CPG” means Columbia Pipeline Group, Inc., a Delaware corporation.

Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages with respect to an Initial Common Unit for each of the Quarters wholly within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and Section 6.5(b) with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

 

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Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or 11.2.

Derivative Instruments” means options, rights, warrants, appreciation rights, tracking profit and phantom interests and other derivative instruments (other than equity interests in the Partnership) relating to, convertible into or exchangeable for Partnership Interests.

Disposed of Adjusted Property” is defined in Section 6.1(d)(xii)(B).

Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

Eligibility Certificate” is defined in Section 4.8(b).

Eligible Holder” means a Limited Partner, or type of Limited Partners, whose (a) U.S. federal income tax status (or lack of proof thereof) does not, in the determination of the General Partner, create or is not reasonably likely to create a substantial risk of the adverse effect described in Section 4.8(a)(i) or (b) nationality, citizenship or other related status does not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture as described in Section 4.8(a)(ii). The General Partner may adopt policies and procedures for determining whether types or categories of Persons are or are not Eligible Holders. The General Partner may determine that certain Persons, or types or categories of Persons, are Eligible Holders based on its determination that (a) their U.S. federal income tax status, nationality, citizenship or other related status (or lack of proof thereof) is unlikely to create the substantial risk referenced or (b) it is in the best interest of the Partnership to permit such Persons or types or categories of Persons to own Partnership Interests notwithstanding any such risk. Any such determination may be changed by the General Partner from time to time in its discretion, and any Limited Partner may be treated as an Ineligible Holder notwithstanding that it was in a type or category of Persons determined by the General Partner to be Eligible Holders at the time such Limited Partner acquired its Limited Partner Interest.

Estimated Incremental Quarterly Tax Amount” is defined in Section 6.9.

Event Issue Value” means, with respect to any Common Unit as of any date of determination, (i) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units, or (ii) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or, if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.

Event of Withdrawal” is defined in Section 11.1(a).

Excess Additional Book Basis” is defined in the definition of Additional Book Basis Derivative Items.

Excess Distribution” is defined in Section 6.1(d)(iii)(A).

Excess Distribution Unit” is defined in Section 6.1(d)(iii)(A).

Expansion Capital Expenditures” means cash expenditures (including transaction expenses) for Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest payments (including periodic net payments under related interest rate swap agreements) and related fees on Construction Debt and paid in respect of the Construction Period. Where cash expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

 

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Final Subordinated Units” is defined in Section 6.1(d)(x)(A).

First Liquidation Target Amount” is defined in Section 6.1(c)(i)(D).

First Target Distribution” means $         per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

Fully Diluted Weighted Average Basis” means, when calculating the number of Outstanding Units for any period, the sum of (1) the weighted average number of Outstanding Units during such period plus (2) all Partnership Interests and Derivative Instruments (a) that are convertible into or exercisable or exchangeable for Units or for which Units are issuable, in each case that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or the Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Interests and Derivative Instruments shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

General Partner” means CPP GP LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in their capacities as general partner of the Partnership (except as the context otherwise requires).

General Partner Interest” means the non-economic management and ownership interest of the General Partner in the Partnership (in its capacity as a general partner and without reference to any Limited Partner Interest held by it) and includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not include any rights to profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership.

Good Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such determination, action or omission was not taken in Bad Faith.

Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

Group” means two or more Persons that with or through any of their respective Affiliates or Associates have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting

 

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(except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power over or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

Group Member” means a member of the Partnership Group.

Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

Hedge Contract” means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in the price of hydrocarbons, interest rates, basis differentials or currency exchange rates in their operations or financing activities, in each case, other than for speculative purposes.

Holder” as used in Section 7.12, is defined in Section 7.12(a).

IDR Reset Common Unit” is defined in Section 5.11(a).

IDR Reset Election” is defined in Section 5.11(a).

Incentive Distribution Right” means a Limited Partner Interest having the rights and obligations specified with respect to Incentive Distribution Rights in this Agreement.

Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4.

Incremental Income Taxes” is defined in Section 6.9.

Indemnified Persons” is defined in Section 7.12(c).

Indemnitee” means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, general partner, employee, agent, fiduciary or trustee of another Person owing a fiduciary or similar duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group’s business and affairs.

 

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Ineligible Holder” is defined in Section 4.8(c).

Initial Common Units” means the Common Units sold in the Initial Offering.

Initial Limited Partners” means the Organizational Limited Partner and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement, including any offer and sale of Common Units pursuant to the exercise of the Over-Allotment Option.

Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters first offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, including sales of debt securities and other incurrences of indebtedness for borrowed money, by any Group Member, other than Working Capital Borrowings; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the Underwriting Agreement) and (c) sales or other dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements.

Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

Limited Partner” means, unless the context otherwise requires, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership.

Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof or interest therein (but excluding Derivative Instruments), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner hereunder.

Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

 

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Liquidation Gain” has the meaning set forth in the definition of Net Termination Gain.

Liquidation Loss” has the meaning set forth in the definition of Net Termination Loss.

Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

LTIP” means benefit plans, programs and practices adopted by the General Partner pursuant to Section 7.5(c).

Maintenance Capital Expenditures” means cash expenditures (including expenditures for the replacement, improvement or expansion of the assets owned by any Group Member or for the acquisition of existing, or the construction or development of new, assets) made to maintain the long-term operating capacity, system integrity and reliability of the Partnership Group.

Merger Agreement” is defined in Section 14.1.

Minimum Quarterly Distribution” means $         per Unit per Quarter (or with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) (or successor to such Section) of the Securities Exchange Act) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such Contributed Property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such Contributed Property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5 but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5 but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

 

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Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

Net Termination Gain” means, as applicable, (a) the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5) that are recognized (i) after the Liquidation Date (“Liquidation Gain”) or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group) (“Sale Gain”), or (b) the excess, if any, of the aggregate amount of Unrealized Gain over the aggregate amount of Unrealized Loss deemed recognized by the Partnership pursuant to Section 5.5(d) on the date of a Revaluation Event (“Revaluation Gain”); provided, however, the items included in the determination of Net Termination Gain shall not include any items of income, gain or loss specially allocated under Section 6.1(d); and provided, further, that Sale Gain and Revaluation Gain shall not include any items of income, gain, loss or deduction that are recognized during any portion of the taxable period during which such Sale Gain or Revaluation Gain occurs.

Net Termination Loss” means, as applicable, (a) the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5) that are recognized (i) after the Liquidation Date (“Liquidation Loss”)or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group) (“Sale Loss”), or (b) the excess, if any, of the aggregate amount of Unrealized Loss over the aggregate amount of Unrealized Gain deemed recognized by the Partnership pursuant to Section 5.5(d) on the date of a Revaluation Event (“Revaluation Loss”); provided, however, items included in the determination of Net Termination Loss shall not include any items of income, gain or loss specially allocated under Section 6.1(d) ; and provided, further, that Sale Loss and Revaluation Loss shall not include any items of income, gain, loss or deduction that are recognized during any portion of the taxable period during which such Sale Loss or Revaluation Loss occurs.

Noncompensatory Option” has the meaning set forth in Treasury Regulation Section 1.721-2(f).

Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

Notice of Election to Purchase” is defined in Section 15.1(b).

Omnibus Agreement” means that certain Omnibus Agreement, dated as of                     , 2015, among the Organizational Limited Partner, the General Partner, CPG and the Partnership.

Operating Expenditures” means all Partnership Group cash expenditures (or the Partnership’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes,

 

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reimbursements of expenses of the General Partner and its Affiliates, payments made under any Hedge Contracts, officer compensation, repayment of Working Capital Borrowings, interest and principal payments on indebtedness and capital expenditures, subject to the following:

(a) repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of “Operating Surplus” shall not constitute Operating Expenditures when actually repaid;

(b) payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;

(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) Investment Capital Expenditures, (iii) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (iv) distributions to Partners, or (v) repurchases of Partnership Interests, other than repurchases of Partnership Interests to satisfy obligations under employee benefit plans, or reimbursements of expenses of the General Partner for such purchases. Where cash expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each; and

(d) (i) payments made in connection with the initial purchase of any Hedge Contract shall be amortized over the life of such Hedge Contract and (ii) payments made in connection with the termination of any Hedge Contract prior to its scheduled settlement or termination date shall be included in equal quarterly installments over what would have been the remaining scheduled term of such Hedge Contract had it not been so terminated.

Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) $         million, (ii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions and provided that cash receipts from the termination of any Hedge Contract prior to its scheduled settlement or termination date shall be included in equal quarterly installments over what would have been the remaining scheduled life of such Hedge Contract had it not been so terminated, (iii) the amount of cash distributions paid in respect of Construction Equity (and incremental Incentive Distributions in respect thereof) and paid in respect of the Construction Period and (iv) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) resulting from dividends or distributions received after the end of such period from equity interests held by the Partnership in any Person other than a Subsidiary in respect of operations conducted by such Person during such period but excluding cash receipts from Interim Capital Transactions by such Persons, less

(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period; (ii) the amount of cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner or the boards of any Subsidiaries of the Partnership to provide funds for future Operating Expenditures; (iii) all Working Capital Borrowings not repaid within twelve (12) months after having been incurred or repaid within such twelve-month period with the proceeds of additional Working Capital Borrowings and (iv) any cash loss realized on disposition of an Investment Capital Expenditure;

 

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provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member), cash received or cash reserves established, increased or reduced after the end of such period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, (x) “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero; and (y) cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

Organizational Limited Partner” means Columbia Energy Group, in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Partnership Interests of any class, none of the Partnership Interests owned by such Person or Group shall be entitled to be voted on any matter or be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Partnership Interests of any class directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Partnership Interests of any class directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply; provided, further, however that Restricted Common Units shall not be treated as Outstanding for purposes of Section 6.1.

Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

 

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Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

Partners” means the General Partner and the Limited Partners.

Partnership” means Columbia Pipeline Partners LP, a Delaware limited partnership.

Partnership Group” means, collectively, the Partnership and its Subsidiaries.

Partnership Interest” means any class or series of equity interest (or, in the case of the General Partner, management interest) in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude all Derivative Instruments.

Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

Percentage Interest” means as of any date of determination and as to any Unitholder with respect to Units, the quotient obtained by dividing (A) the number of Units held by such Unitholder by (B) the total number of Outstanding Units. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero. The Percentage Interest with respect to the General Partner Interest shall at all times be zero.

Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

Privately Placed Units” means any Common Units issued for cash or property other than pursuant to a public offering.

Pro Rata” means when used with respect to (a) Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests and (c) holders of Incentive Distribution Rights, apportioned among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership in which the Closing Date occurs, the portion of such fiscal quarter after the Closing Date.

Rate Eligibility Trigger” is defined in Section 4.8(a)(i).

Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

 

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Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

Record Holder” means (a) with respect to any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the closing of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the closing of business on such Business Day.

Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

Registration Rights Agreement” means that certain Registration Rights Agreement, dated as of                     , 2015, among the Organizational Limited Partner and the Partnership.

Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-198990) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders, the excess of (a) the Net Positive Adjustments of the Unitholders as of the end of such period over (b) the sum of those Unitholders’ Share of Additional Book Basis Derivative Items for each prior taxable period, and (ii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

Reset MQD” is defined in Section 5.11(a).

Reset Notice” is defined in Section 5.11(b).

Restricted Common Unit” means a Common Unit (i) that was granted to the holder thereof in connection with such holder’s performance of services for the Partnership, (ii) that remains subject to a “substantial risk of forfeiture” within the meaning of Section 83 of the Code and (iii) with respect to which no election was made pursuant to Section 83(b) of the Code. As set forth in the final proviso in the definition of “Outstanding,” Restricted Common Units are not treated as Outstanding for purposes of Section 6.1. Upon the lapse of the “substantial risk of forfeiture” with respect to a Restricted Common Unit, for U.S. federal income tax purposes such Common Unit will be treated as having been newly issued in consideration for the performance of services and will thereafter be considered to be Outstanding for purposes of Section 6.1.

Revaluation Event” means an event that results in adjustment of the Carrying Value of each Partnership property pursuant to Section 5.5(d).

 

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Revaluation Gain” has the meaning set forth in the definition of Net Termination Gain.

Revaluation Loss” has the meaning set forth in the definition of Net Termination Loss.

Sale Gain” has the meaning set forth in the definition of Net Termination Gain.

Sale Loss” has the meaning set forth in the definition of Net Termination Loss.

Second Liquidation Target Amount” is defined in Section 6.1(c)(i)(E).

Second Target Distribution” means $         per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time, and (ii) with respect to the holders of Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the holders of the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

Special Approval” means approval by a majority of the members of the Conflicts Committee, whether in the form of approval or approval and recommendation to the Board of Directors.

Subordinated Unit” means a Partnership Interest having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not refer to or include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

(a) the first Business Day following the distribution pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending                     , 2018 in respect of which (i) (A) aggregate distributions from Operating Surplus on the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such Business Day equaled or exceeded the sum of the Minimum Quarterly Distribution on all such Outstanding Common Units, Subordinated Units and other Outstanding Units in each respective period and (B) the Adjusted Operating Surplus for such periods immediately preceding such Business Day equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during each such period on a Fully Diluted Weighted Average Basis, and (ii) there are no Cumulative Common Unit Arrearages; and

 

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(b) the first Business Day following the distribution pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending                     , 2016, in respect of which (i) (A) aggregate distributions from Operating Surplus on the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, with respect to the four-Quarter period immediately preceding such Business Day equaled or exceeded 150% of the Minimum Quarterly Distribution on all such Outstanding Common Units, Subordinated Units and other Outstanding Units, and (B) the Adjusted Operating Surplus for such period equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Common Units and Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis and the corresponding Incentive Distributions and (ii) there are no Cumulative Common Unit Arrearages.

Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, directly or by one or more Subsidiaries of such Person, or a combination thereof, controls such partnership, directly or indirectly, at the date of determination or (c) any other Person in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

Surviving Business Entity” is defined in Section 14.2(b)(ii).

Target Distribution” means each of the Minimum Quarterly Distribution, the First Target Distribution, Second Target Distribution and Third Target Distribution.

Third Target Distribution” means $         per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

Trading Day” means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted to trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

transfer” is defined in Section 4.4(a).

Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided, that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

Treasury Regulation” means the United States Treasury regulations promulgated under the Code.

Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

 

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Underwriting Agreement” means that certain Underwriting Agreement, dated as of                     , 2015, among the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) the General Partner Interest or (ii) Incentive Distribution Rights.

Unitholders” means the Record Holders of Units.

Unit Majority” means (i) during the Subordination Period, a majority of the Outstanding Common Units (excluding Common Units whose voting power is, for purposes of the applicable matter for which a vote of the Unitholders is being taken, beneficially owned by the General Partner or its Affiliates), voting as a class, and a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, a majority of the Outstanding Common Units.

Unpaid MQD” is defined in Section 6.1(c)(i)(B).

Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision, or combination of such Units.

Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement.

U.S. GAAP” means U.S. generally accepted accounting principles, as in effect from time to time, consistently applied.

U.S. means the United States of America.

Withdrawal Opinion of Counsel” is defined in Section 11.1(b).

Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners, made pursuant to a credit facility, commercial paper facility or other similar financing arrangement; provided that when incurred it is the intent of the borrower to repay such borrowings within 12 months from sources other than additional Working Capital Borrowings. The General Partner may treat the temporary use of cash reserved to fund Expansion Capital Expenditures as Working Capital Borrowings, including to temporarily use such cash to pay Operating Expenditures; provided that when such Expansion Capital Expenditures are in fact made (or twelve months after the date such cash was treated as Working Capital Borrowings, if earlier), the amount treated as Working Capital Borrowings shall be treated as a repayment of Working Capital Borrowings.

 

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Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. Any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in good faith shall, in each case, be conclusive and binding on all Record Holders and all other Persons for all purposes.

ARTICLE II

ORGANIZATION

Section 2.1 Formation. The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act. The General Partner and the Organizational Limited Partner hereby amend and restate the original Agreement of Limited Partnership of the Partnership in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.

Section 2.2 Name. The name of the Partnership shall be “Columbia Pipeline Partners LP.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 2711 Centerville Road, Suite 400, Wilmington, Delaware 19808, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporate Service Company. The principal office of the Partnership shall be located at 5151 San Felipe St., Suite 2500, Houston, Texas 77056, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 5151 San Felipe St., Suite 2500, Houston, Texas 77056, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity,

 

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and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership Group of any business.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of the Partnership’s designated Affiliates as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director,

 

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employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be considered participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.6, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) Each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense, to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) shall be satisfied if the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act);

(ii) a current list of the name and last known business, residence or mailing address of each Record Holder; and

(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed.

(b) The rights pursuant to Section 3.4(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have any rights as Partners to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.4(a).

(c) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential.

(d) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person.

 

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ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that are issued shall be executed on behalf of the Partnership by the Chairman of the Board, Chief Executive Officer, President, General Counsel or any Executive Vice President or Vice President and the Chief Financial Officer or the Corporate Secretary or any Assistant Corporate Secretary of the General Partner. No Certificate for a class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Partnership Interests; provided, however, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units, the Record Holders of such Subordinated Units (a) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units or (b) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

 

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(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction by which the holder of a Partnership Interest assigns such Partnership Interest to another Person who is or becomes a Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise (but not the pledge, grant of security interest, encumbrance, hypothecation or mortgage), including any transfer upon foreclosure or other exercise of remedies of any pledge, security interest, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in such Partner and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent

 

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shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 4.5 and except as provided in Section 4.8, each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) acknowledges and agrees to the provisions of Section 10.1(a).

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units, Common Units and Incentive Distribution Rights to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) The General Partner may at its option transfer all or any part of its General Partner Interest without approval from any other Partner.

(b) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2 be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal

 

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income tax purposes or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of a majority of the Outstanding Limited Partner Interests of such class.

(c) Nothing contained in this Agreement, other than Section 4.7(a), shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

Section 4.8 Eligibility Certificates; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that:

(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners (or type of Limited Partners) or their owners creates or is reasonably likely to create a substantial risk of an adverse effect on the rates that can be charged to customers by any Group Member with respect to assets that are subject to regulation by the Federal Energy Regulatory Commission or similar regulatory body (a “Rate Eligibility Trigger”); or

(ii) the nationality, citizenship or other related status (or lack of proof thereof) of one or more Limited Partners (or type of Limited Partners) or their owners creates or is reasonably likely to create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest under any federal, state or local law or regulation (a “Citizenship Eligibility Trigger”);

then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or appropriate to (x) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Limited Partners and, to the extent relevant, their owners, as the General Partner determines to be necessary or appropriate to reduce the risk of occurrence of a material adverse effect on the rates that can be charged to customers by any Group Member or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status of the Limited Partners and, to the extent relevant, their owners as the General Partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

(b) Such amendments may include provisions requiring all Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as Partners (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner (or its owner) is not an Eligible Holder (an “Ineligible Holder”), the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner shall be substituted and treated as the owner of all Partnership Interests owned by an Ineligible Holder.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, cast such votes in the same manner and in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast.

 

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(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for purposes hereof as a purchase by the Partnership from the Ineligible Holder of the portion of his Partnership Interest representing his right to receive his share of such distribution in kind.

(f) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Partnership Interests of such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the owner in respect of such Ineligible Holder’s Partnership Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Partner fails to furnish an Eligibility Certificate or other information requested within the period of time specified in amendments adopted pursuant to Section 4.8 or if upon receipt of such Eligibility Certificate, the General Partner determines, with the advice of counsel, that a Partner is an Ineligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, as applicable, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the lesser of (a) the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed or (b) the price paid for such Partnership Interests by the Partner, in either case, multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

 

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(b) The provisions of this Section 4.9 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption will be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Organizational Contributions. In connection with the formation of the Partnership under the Delaware Act, the General Partner has been admitted as the General Partner of the Partnership. The Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $1,000.00 in exchange for a Limited Partner Interest equal to a 100% Percentage Interest and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, and effective with the admission of another Limited Partner to the Partnership, the interests of the Organizational Limited Partner will be redeemed as provided in the Contribution Agreement and the initial Capital Contributions of the Organizational Limited Partner will be refunded.

Section 5.2 Contributions by the General Partner and its Affiliates. On the Closing Date and pursuant to the Contribution Agreement, the Organizational Limited Partner shall contribute to the Partnership, as a Capital Contribution, Class A Units (as defined in the Contribution Agreement) in exchange for Common Units, Subordinated Units and the Incentive Distribution Rights, collectively.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.4 Interest and Withdrawal. No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

 

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Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made by the Partner with respect to such Partnership Interest and (ii) all items of Partnership income and gain computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made to the Partner with respect to such Partnership Interest, provided that the Capital Account of a Partner shall not be reduced by the amount of any distributions made with respect to Restricted Common Units held by such Partner and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (A) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (B) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) The computation of all items of income, gain, loss and deduction shall be made (x) except as otherwise provided in this Agreement and Treasury Regulation Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that may be made by the Partnership, and (y) as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(iv) To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(v) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.5(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.

 

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(vi) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the property’s Carrying Value as of such date.

(vii) Any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property or Adjusted Property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d) as if the adjusted basis of such property were equal to the Carrying Value of such property.

(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to the Carrying Values of Partnership property. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) (i) Except as otherwise provided in this Section 5.5(c), a transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(b), immediately prior to the transfer of (1) an Affiliate Retained Unit, (2) a Subordinated Unit or (3) a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (in each case, other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to such transferred Units will (A) first, be allocated to the Units or be transferred in an amount equal to the product of (x) the number of such Units to be transferred and (y) the Per Unit Capital Amount for an initial Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Units. Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Affiliate Retained Units, Subordinated Units or retained converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) above, and the transferee’s Capital Account established with respect to the transferred Units will have a balance equal to the amount allocated under clause (A) above.

(iii) Subject to Section 6.8(b), immediately prior to the transfer of an IDR Reset Common Unit by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(iii) apply), the Capital Account maintained for such Person with respect to its IDR Reset Common Units will (A) first, be allocated to the IDR Reset Common Units to be transferred in an amount equal to the product of (x) the number of such IDR Reset Common Units to be transferred and (y) the Per Unit Capital Amount for an initial Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any IDR Reset Common Units. Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained IDR Reset Common Units, if any, will have a balance equal to the amount allocated under clause (B) above, and the transferee’s Capital Account established with respect to the transferred IDR Reset Common Units will have a balance equal to the amount allocated under clause (A) above.

(d) (i) Consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(iv)(h)(2), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of a Noncompensatory Option, the issuance of Partnership Interests as consideration for the provision of services (including upon the lapse of a “substantial risk of forfeiture” with respect to a Restricted Common Unit), the issuance of IDR Reset Common Units pursuant to Section 5.11, or the conversion of the Combined Interest to

 

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Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property; provided, however, that in the event of the issuance of a Partnership Interest pursuant to the exercise of a Noncompensatory Option where the right to share in Partnership capital represented by such Partnership Interest differs from the consideration paid to acquire and exercise such option, the Carrying Value of each Partnership property immediately after the issuance of such Partnership Interest shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property and the Capital Accounts of the Partners shall be adjusted in a manner consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(s); provided further, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, in the event of an issuance of a Noncompensatory Option to acquire a de minimis Partnership Interest or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of a Revaluation Event resulting from the exercise of a Noncompensatory Option, immediately after the issuance of the Partnership Interest acquired pursuant to the exercise of such Noncompensatory Option) shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time and the value of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of a distribution other than one made pursuant to Section 12.4, be determined in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Interests and Derivative Instruments.

(a) The Partnership may issue additional Partnership Interests and Derivative Instruments for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior or junior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the

 

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Partnership may or shall be required to redeem the Partnership Interest (including sinking fund provisions); (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by Certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Instruments pursuant to this Section 5.6, (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.11, (iv) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holders of such Limited Partner Interests and (v) all additional issuances of Partnership Interests and Derivative Instruments. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests and Derivative Instruments being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests and Derivative Instruments or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution pursuant to Section 6.4(a) in respect of the final full Quarter of the Subordination Period.

(b) The Subordinated Units may convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

Section 5.8 Limited Preemptive Right. Except as provided in this Section 5.8 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests. The determination by the General Partner to exercise (or refrain from exercising) its right pursuant to the immediately preceding sentence shall be a determination made in its individual capacity.

Section 5.9 Splits and Combinations.

(a) The Partnership may make a distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests. Upon any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event (subject to the effect of Section 5.9(d)), and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units shall be proportionately adjusted retroactively to the beginning of the Partnership.

 

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(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision, combination or reorganization. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6(d) and this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 or 17-804 of the Delaware Act.

Section 5.11 Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the holders of Incentive Distribution Rights) shall have the option, at any time when there are no Subordinated Units outstanding and the Partnership has made a distribution pursuant to Section 6.4(a)(vii) or Section 6.4(b)(v) for each of the four most recently completed Quarters and the aggregate amounts distributed in respect of such four-Quarter period did not exceed Adjusted Operating Surplus for such four-Quarter period, to make an election (the “IDR Reset Election”) to cause the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their Pro Rata share of a number of Common Units (the “IDR Reset Common Units”) equal to the result of dividing (i) the amount of cash distributions made by the Partnership for the Quarter immediately preceding the giving of the Reset Notice in respect of the Incentive Distribution Rights by (ii) the cash distribution made by the Partnership in respect of each Common Unit for the Quarter immediately preceding the giving of the Reset Notice (the “Reset MQD”) (the number of Common Units determined by such quotient is referred to herein as the “Aggregate Quantity of IDR Reset Common Units”). The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive Common Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

 

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(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice”) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of Common Units that each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Common Units to be issued pursuant to this Section 5.11 on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion (on terms acceptable to the National Securities Exchange upon which the Common Units are then traded) of such Partnership Interests into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Target Distributions shall be adjusted at the time of the issuance of Common Units or other Partnership Interests pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to be equal to the Reset MQD, (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.

(f) Upon the issuance of IDR Reset Common Units pursuant to Section 5.11(a) (or other Partnership Interests as described in Section 5.11(d)), the Capital Account maintained with respect to the Incentive Distribution Rights shall (i) first, be allocated to IDR Reset Common Units (or other Partnership Interests) in an amount equal to the product of (A) the Aggregate Quantity of IDR Reset Common Units (or other Partnership Interests) and (B) the Per Unit Capital Amount for an Initial Common Unit, and (ii) second, any remaining balance in such Capital Account will be retained by the holder(s) of the Incentive Distribution Rights. If there is not a sufficient Capital Account associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an Initial Common Unit to the IDR Reset Common Units in accordance with clause (i) of this Section 5.11(f), the IDR Reset Common Units shall be subject to Sections 6.1(d)(x)(B) and (C).

 

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Section 5.12 Deemed Capital Contributions.

Consistent with the principles of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then for tax purposes, (x) such property shall be treated as having been contributed to the Partnership by such Partner and (y) immediately thereafter the Partnership shall be treated as having transferred such property to the employee or other service provider.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b)) for each taxable period shall be allocated among the Partners as provided herein below. As set forth in the definition of “Outstanding,” Restricted Common Units shall not be considered to be Outstanding Common Units for purposes of this Section 6.1 and references herein to Unitholders holding Common Units shall be to such Unitholders solely with respect to their Common Units other than Restricted Common Units.

(a) Net Income. Net Income for each taxable period (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Income for such taxable period) shall be allocated as follows:

(i) First, to the General Partner until the aggregate amount of Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate amount of Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods; and

(ii) Second, the balance, if any, 100% to the Unitholders, Pro Rata.

(b) Net Loss. Net Loss for each taxable period (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Loss for such taxable period) shall be allocated as follows:

(i) First, to the Unitholders, Pro Rata; provided, that Net Loss shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

(ii) Second, the balance, if any, 100% to the General Partner.

(c) Net Termination Gains and Losses. Any Net Termination Gain or Net Termination Loss occurring during a taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of cash and cash equivalents provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4; and provided, further, that Net Termination

 

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Gain or Net Termination Loss attributable to (i) Liquidation Gain or Liquidation Loss shall be allocated on the last day of the taxable period during which such Liquidation Gain or Liquidation Loss occurred, (ii) Sale Gain or Sale Loss shall be allocated as of the time of the sale or disposition giving rise to such Sale Gain or Sale Loss and allocated to the Partners consistent with the second proviso set forth in Section 6.2(f) and (iii) Revaluation Gain or Revaluation Loss shall be allocated on the date of the Revaluation Event giving rise to such Revaluation Gain or Revaluation Loss.

(i) Except as provided in Section 6.1(c)(iv) and subject to the provisions set forth in the last sentence of this Section 6.1(c)(i), Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated in the following order and priority:

(A) First, to each Partner having a deficit balance in its Adjusted Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Adjusted Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Adjusted Capital Account;

(B) Second, to all Unitholders holding Common Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) if the Net Termination Gain is attributable to Liquidation Gain, the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter referred to as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage with respect to such Common Unit;

(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit into a Common Unit, to all Unitholders holding Subordinated Units, Pro Rata, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) if the Net Termination Gain is attributable to Liquidation Gain, the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

(D) Fourth, to all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, if applicable, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter after the Closing Date or the date of the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of cash or cash equivalents that are deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) with respect to such Common Unit for such period (the sum of (1), (2), (3) and (4) is hereinafter referred to as the “First Liquidation Target Amount”);

(E) Fifth, 15% to the holders of the Incentive Distribution Rights, Pro Rata, and 85.0% to all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter after the Closing Date or the date of the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of cash or cash equivalents that are deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) with respect to such Common Unit for such period (the sum of (1) and (2) is hereinafter referred to as the “Second Liquidation Target Amount”);

 

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(F) Sixth, 25% to the holders of the Incentive Distribution Rights, Pro Rata, and 75% to all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter after the Closing Date or the date of the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of cash or cash equivalents that are deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv) with respect to such Common Unit for such period; and

(G) Finally, 50% to the holders of the Incentive Distribution Rights, Pro Rata, and 50% to all Unitholders, Pro Rata.

Notwithstanding the foregoing provisions in this Section 6.1(c)(i), the General Partner may adjust the amount of any Net Termination Gain arising in connection with a Revaluation Event that is allocated to the holders of Incentive Distribution Rights in a manner that will result (1) in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value and (2) to the greatest extent possible, the Capital Account with respect to the Incentive Distribution Rights that are Outstanding prior to such Revaluation Event being equal to the amount of Net Termination Gain that would be allocated to the holders of the Incentive Distribution Rights pursuant to this Section 6.1(c)(i) if (i) the Capital Accounts with respect to all Partnership Interests that were Outstanding immediately prior to such Revaluation Event were equal to zero and (ii) the aggregate Carrying Value of all Partnership property equaled the aggregate amount of all Partnership Liabilities.

(ii) Except as otherwise provided by Section 6.1(c)(iii) or Section 6.1(c)(iv), Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Loss) shall be allocated:

(A) First, if Subordinated Units remain Outstanding, to all Unitholders holding Subordinated Units, Pro Rata, until the Adjusted Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, to all Unitholders holding Common Units, Pro Rata, until the Adjusted Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

(C) Third, the balance, if any, 100% to the General Partner.

(iii) Net Termination Loss attributable to Revaluation Loss and deemed recognized prior to the conversion of the last Outstanding Subordinated Unit and prior to the Liquidation Date shall be allocated:

(A) First, to the Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding equals the Event Issue Value; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account);

(B) Second, to all Unitholders holding Subordinated Units, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(B) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and

(C) Third, the balance, if any, to the General Partner.

 

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(iv) If (A) a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), (B) a Net Termination Gain or Net Termination Loss subsequently occurs (other than as a result of a Revaluation Event) prior to the conversion of the last Outstanding Subordinated Unit and (C) after tentatively making all allocations of such Net Termination Gain or Net Termination Loss provided for in Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable, the Capital Account in respect of each Common Unit then Outstanding does not equal the amount such Capital Account would have been if Section 6.1(c)(iii) had not been part of this Agreement and all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable, then items of income, gain, loss and deduction included in such Net Termination Gain or Net Termination Loss, as applicable, shall be specially allocated to the General Partner and all Unitholders in a manner that will, to the maximum extent possible, cause the Capital Account in respect of each Common Unit then Outstanding to equal the amount such Capital Account would have been if all allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for each taxable period in the following order:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to an Outstanding Unit for a taxable period exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Outstanding Unit for the same taxable period (the amount of the excess, an “Excess Distribution” and the Unit with respect to which the

 

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greater distribution is paid, an “Excess Distribution Unit”), then there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution.

(B) After the application of Section 6.1(d)(iii)(A), the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable period.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

(v) Gross Income Allocation. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, the Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated first, to any Partner that contributed property to the Partnership in proportion to and to the extent of the amount by which each such Partner’s share of any Section 704(c) built-in gains exceeds such Partner’s share of Nonrecourse Built-in Gain, and second, among the Partners Pro Rata.

 

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(ix) Certain Distributions Subject to Section 734(b). To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts as a result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) taken into account pursuant to Section 5.5, and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (1) the number of Final Subordinated Units held by such Partner and (2) the Per Unit Capital Amount for an Outstanding Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

(B) Prior to making any allocations pursuant to Section 6.1(d)(xii)(C), if a Revaluation Event occurs during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.11, then after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.11 equaling the product of (1) the Aggregate Quantity of IDR Reset Common Units and (2) the Per Unit Capital Amount for an Initial Common Unit.

(C) Prior to making any allocations pursuant to Section 6.1(d)(xii)(C), if a Revaluation Event occurs after the Subordination Period has ended, then after the application of Sections 6.1(d)(x)(A)-(B), any remaining Unrealized Gains and Unrealized Losses shall be allocated to the holders of (1) Affiliate Retained Units, Pro Rata, or (2) Outstanding Common Units (other than Affiliate Retained Units), Pro Rata, as applicable, in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to each Affiliate Retained Unit equaling the Per Unit Capital Amount for an Initial Common Unit.

(D) Prior to making any allocations pursuant to Section 6.1(d)(xii)(C), if a Revaluation Event occurs, then after the application of Sections 6.1(d)(x)(A)-(C), any remaining Unrealized Gains and Unrealized Losses shall be allocated to the holders of (A) Outstanding Privately Placed Units, Pro Rata, or (B) Outstanding

 

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Common Units (other than Privately Placed Units), Pro Rata, as applicable, in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to each Privately Placed Unit equaling the Per Unit Capital Amount for an Initial Common Unit.

(E) With respect to any taxable period during which an IDR Common Reset Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Common Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Common Unit to an amount equal to the Per Unit Capital Amount for an Initial Common Unit.

(F) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof) that are publicly traded as a single class, the General Partner shall (1) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (2) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (3) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof) that are publicly traded as a single class. The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(F) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests or the Partnership.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or a Net Termination Loss, the following rules shall apply:

(A) The General Partner shall allocate Additional Book Basis Derivative Items consisting of depreciation, amortization, depletion or any other form of cost recovery (other than Additional Book Basis Derivative Items included in Net Termination Gain or Net Termination Loss) with respect to any Adjusted

 

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Property to the Unitholders, Pro Rata, to the holders of Incentive Distribution Rights and to the General Partner, all in the same proportion as the Net Termination Gain or Net Termination Loss resulting from the Revaluation Event that gave rise to such Additional Book Basis Derivative Items was allocated to them pursuant to Section 6.1(c).

(B) If a sale or other taxable disposition of an Adjusted Property, including, for this purpose, inventory (“Disposed of Adjusted Property”) occurs other than in connection with an event giving rise to Sale Gain or Sale Loss, the General Partner shall allocate (1) items of gross income and gain (x) away from the holders of Incentive Distribution Rights and (y) to the Unitholders, or (2) items of deduction and loss (x) away from the Unitholders and (y) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items with respect to the Disposed of Adjusted Property (determined in accordance with the last sentence of the definition of Additional Book Basis Derivative Items) treated as having been allocated to the Unitholders pursuant to this Section 6.1(d)(xii)(B) exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For purposes of this Section 6.1(d)(xii)(B), the Unitholders shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C) Net Termination Loss in an amount equal to the lesser of (1) such Net Termination Loss and (2) the Aggregate Remaining Net Positive Adjustments shall be allocated in such manner as is determined by the General Partner that to the extent possible, the Capital Account balances of the Partners will equal the amount they would have been had no prior Book-Up Events occurred, and any remaining Net Termination Loss shall be allocated pursuant to Section 6.1(c) hereof. In allocating Net Termination Loss pursuant to this Section 6.1(d)(xii)(C), the General Partner shall attempt, to the extent possible, to cause the Capital Accounts of the Unitholders, on the one hand, and holders of the Incentive Distribution Rights, on the other hand, to equal the amount they would equal if (i) the Carrying Values of the Partnership’s property had not been previously adjusted in connection with any prior Book-Up Events, (ii) Unrealized Gain and Unrealized Loss (or, in the case of a liquidation, Liquidation Gain or Liquidation Loss) with respect to such Partnership Property were determined with respect to such unadjusted Carrying Values, and (iii) any resulting Net Termination Gain had been allocated pursuant to Section 6.1(c)(i) (including, for the avoidance of doubt, taking into account the provisions set forth in the last sentence of Section 6.1(c)(i)).

(D) In making the allocations required under this Section 6.1(d)(xii)(D), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii)(D). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for U.S. federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in Section 6.1(d)(xii)(A), (B) and (C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii)(D).

(xiii) Special Curative Allocation in Event of Certain Liquidations.

 

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(A) Liquidation Prior to Conversion of the Last Outstanding Subordinated Unit. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if (1) the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit and (2) after having made all other allocations provided for in this Section 6.1 for the taxable period in which the Liquidation Date occurs, the Capital Account in respect of each then Outstanding Common Unit does not equal the amount such Capital Account would have been if Section 6.1(c)(iii) and Section 6.1(c)(iv) had not been part of this Agreement and all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable, then items of income, gain, loss and deduction for such taxable period shall be reallocated among all Unitholders in a manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable. For the avoidance of doubt, the reallocation of items set forth in the immediately preceding sentence provides that, to the extent necessary to achieve the Capital Account balances described above, (x) items of income and gain that would otherwise be included in Net Income or Net Loss, as the case may be, for the taxable period in which the Liquidation Date occurs shall be reallocated from the Unitholders holding Subordinated Units to Unitholders holding Common Units and (y) items of deduction and loss that would otherwise be included in Net Income or Net Loss, as the case may be, for the taxable period in which the Liquidation Date occurs shall be reallocated from Unitholders holding Common Units to Unitholders holding Subordinated Units. In the event that (1) the Liquidation Date occurs on or before the date (not including any extension of time prescribed by law) for the filing of the Partnership’s federal income tax return for the taxable period immediately prior to the taxable period in which the Liquidation Date occurs and (2) the reallocation of items for the taxable period in which the Liquidation Date occurs as set forth above in this Section 6.1(d)(xiii)(A) fails to achieve the Capital Account balances described above, items of income, gain, loss and deduction that would otherwise be included in the Net Income or Net Loss, as the case may be, for such prior taxable period shall be reallocated among the General Partner and all Unitholders in a manner that will, to the maximum extent possible and after taking into account all other allocations made pursuant to this Section 6.1(d)(xiii)(A), cause the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

(B) Liquidation After Conversion of the Last Outstanding Subordinated Unit.

(1) Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if (x) the Liquidation Date occurs after the conversion of the last Outstanding Subordinated Unit and (y) after having made all other allocations provided for in this Section 6.1 for the taxable period in which the Liquidation Date occurs, the Capital Account maintained with respect to each Affiliate Retained Unit does not equal the Per Unit Capital Amount for an Initial Common Unit, then items of gain and loss (including Unrealized Gain and Unrealized Loss) for such taxable period resulting from the sale, exchange or other disposition of assets of the Partnership Group (including any such items included in Net Termination Gain or Net Termination Loss for such period but excluding any items of income or deduction included in such Net Termination Gain or Net Termination Loss) shall be reallocated to the Unitholders in a manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Accounts maintained with respect to each Affiliate Retained Unit to equal the Per Unit Capital Amount for an Initial Common Unit.

(2) In the event that the reallocation of items for the taxable period in which the Liquidation Date occurs as set forth above in Section 6.1(d)(xiii)(B)(1) fails to achieve the Capital Account balances described therein, items of income, gain, loss and deduction that would otherwise be included in (x) Net

 

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Income or Net Loss, as the case may be, or (y) Net Termination Gain or Net Termination Loss, as the case may be, for the taxable period in which the Liquidation Date occurs shall be reallocated among the Unitholders in a manner that will, to the maximum extent possible and after taking into account all other allocations made pursuant to this Section 6.1(d)(xiii), cause the Capital Account maintained with respect to each Affiliate Retained Unit to equal the Per Unit Capital Amount for an Initial Common Unit; provided that the amount of items allocated pursuant to this Section 6.1(d)(xiii)(B)(2) shall not exceed the aggregate amount of items of gross income reallocated pursuant to Section 6.1(d)(xiv) with respect to taxable periods ending more than five years prior to the end of the taxable period in which the Liquidation Date occurs.

(3) In the event that (x) the Liquidation Date occurs on or before the date (not including any extension of time prescribed by law) for the filing of the Partnership’s federal income tax return for the taxable period immediately prior to the taxable period in which the Liquidation Date occurs, and (y) the reallocations of items for the taxable period in which the Liquidation Date occurs as set forth above in Section 6.1(d)(xiii)(B)(1) and (2) fail to achieve the Capital Account balances described therein, items of income, gain, loss and deduction that would otherwise be included in (i) Net Income or Net Loss, as the case may be, or (ii) Net Termination Gain or Net Termination Loss, as the case may be, for such prior taxable period shall be reallocated among the Unitholders in a manner that will, to the maximum extent possible and after taking into account all other allocations made pursuant to this Section 6.1(d)(xiii), cause the Capital Account maintained with respect to each Affiliate Retained Unit to equal the Per Unit Capital Amount for an Initial Common Unit; provided that the amount of items allocated pursuant to this Section 6.1(d)(xiii)(B)(3) shall not exceed an amount equal to the excess, if any, of (a) the aggregate amount of items of gross income reallocated pursuant to Section 6.1(d)(xiv) with respect to taxable periods ending more than six years prior to the end of the taxable period in which the Liquidation Date occurs, over (b) any amounts reallocated pursuant to Section 6.1(d)(xiii)(B)(2).

(xiv) Special Reallocation of Gross Income to Common Units. After taking into account (A) the allocation of Net Income pursuant to Section 6.1 or Net Loss pursuant to Section 6.2 and (B) the Required Allocations (including any Curative Allocations) for each taxable period ending on or before December 31, 2021 during which any Affiliate Retained Units are Outstanding, items of gross income that would otherwise be allocated to the holders of such Affiliate Retained Units shall be reallocated from the holders of such Affiliate Retained Units, Pro Rata, to the holders of Common Units other than Affiliate Retained Units, Pro Rata; provided that no reallocation of items of gross income shall be made pursuant to this Section 6.1(d)(xiv) in any taxable period to the extent such allocation would cause a hypothetical holder of an Initial Common Unit to be allocated under this Agreement an amount of federal taxable income with respect to such taxable period that would exceed 20% of the amount of cash distributed by the Partnership to such holder with respect to such Initial Common Unit for such taxable period.

(xv) Allocations Regarding Certain Payments Made to Employees and Other Service Providers. Consistent with the principles of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then any items of deduction or loss resulting from or attributable to such transfer shall be allocated to the Partner (or its successor) that made such transfer and such Partner shall be deemed to have contributed such property to the Partnership pursuant to Section 5.12.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

 

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(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(d)(x)(E)); provided, that in all events the General Partner shall apply the “remedial allocation method” in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(f) Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Closing Date occurs shall be allocated to the Partners (including all Persons who acquire Units pursuant to the Contribution Agreement) as of the closing of the National Securities Exchange on which Partnership Interests are listed or admitted to trading on the last Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such item is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

 

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(g) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

(h) If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).

Section 6.3 Distributions; Characterization of Distributions; Distributions to Record Holders.

(a) The General Partner may adopt a cash distribution policy, which it may change from time to time without amendment to this Agreement. Distributions will be made as and when declared by the General Partner.

(b) All amounts of cash and cash equivalents distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of cash and cash equivalents theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of cash and cash equivalents distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement or otherwise made by the Partnership shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.

(c) Notwithstanding Section 6.3(b), in the event of the dissolution and liquidation of the Partnership, all Partnership assets shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions from Operating Surplus.

(a) During Subordination Period. Cash and cash equivalents distributed in respect of any Quarter wholly within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall be distributed as follows:

(i) First, to all Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, to all Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

(iii) Third, to all Unitholders holding Subordinated Units, Pro Rata, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

 

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(iv) Fourth, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(v) Fifth, (A) 15% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 85% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(vi) Sixth, (A) 25% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 75% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

(vii) Thereafter, (A) 50% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 50% to all Unitholders, Pro Rata;

provided, however, if the Target Distributions have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of cash and cash equivalents that are deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).

(b) After Subordination Period. Cash and cash equivalents distributed in respect of any Quarter ending after the Subordination Period has ended that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall be distributed as follows:

(i) First, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(iii) Third, (A) 15% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 85% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(iv) Fourth, (A) 25% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 75% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

(v) Thereafter, (A) 50% to the holders of the Incentive Distribution Rights, Pro Rata; and (B) 50% to all Unitholders, Pro Rata;

provided, however, if the Target Distributions have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of cash or cash equivalents that are deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(v).

Section 6.5 Distributions from Capital Surplus. Cash and cash equivalents that are distributed and deemed to be Capital Surplus pursuant to the provisions of Section 6.3(b) shall be distributed, unless the provisions of Section 6.3 require otherwise:

(a) First, 100% to the Unitholders, Pro Rata, until the Minimum Quarterly Distribution has been reduced to zero pursuant to the second sentence of Section 6.6(a);

 

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(b) Second, 100% to all Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage; and

(c) Thereafter, all cash and cash equivalents that are distributed shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Target Distribution Levels.

(a) The Target Distributions, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests. In the event of a distribution of cash or cash equivalents that is deemed to be from Capital Surplus, the then applicable Target Distributions shall be reduced in the same proportion that the distribution had to the fair market value of the Common Units immediately prior to the announcement of the distribution. If the Common Units are publicly traded on a National Securities Exchange, the fair market value will be the Current Market Price before the ex-dividend date. If the Common Units are not publicly traded, the fair market value will be determined by the Board of Directors.

(b) The Target Distributions shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding Subordinated Units shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such converted Subordinated Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x), and 6.7(b) and (c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or retained converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) The Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii) and 6.1(d)(x)(C); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

 

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Section 6.8 Special Provisions Relating to the Holders of IDR Reset Common Units.

(a) A Unitholder shall not be permitted to transfer an IDR Reset Common Unit (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained IDR Reset Common Units would be negative after giving effect to the allocation under Section 5.5(c)(iii).

(b) A Unitholder holding an IDR Reset Common Unit shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that upon transfer each such Common Unit should have, as a substantive matter, like intrinsic economic and U.S. federal income tax characteristics to the transferee, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an Initial Common Unit to such transferee. In connection with the condition imposed by this Section 6.8(b), the General Partner may apply Sections 5.5(c)(ii), 6.1(d)(x) and 6.8(a) or, to the extent not resulting in a material adverse effect on the Unitholders holding Common Units, take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such IDR Reset Common Units.

Section 6.9 Entity-Level Taxation. If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, in its sole discretion, reduce the Target Distributions by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes”), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Target Distributions for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Target Distributions, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) cash and cash equivalents with respect to such Quarter by (ii) the sum of cash and cash equivalents with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, cash and cash equivalents with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, but without limitation on the ability of the General Partner to delegate its rights and power to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no other Partner shall have any management

 

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power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted to a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.4, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.4 or Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of cash or cash equivalents by the Partnership;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “chief executive officer,” “president,” “chief financial officer,” “chief operating officer,” “general counsel,” “vice president,” “corporate secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time);

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

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(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange;

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Instruments;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member; and

(xv) the entering into agreements with any of its Affiliates, including agreements to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Contribution Agreement, the Omnibus Agreement, the Registration Rights Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in the case of each agreement other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own behalf or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners, or the other Persons who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; and (iii) agrees that (A) the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) and (B) the General Partner’s determination to issue equity or debt securities in order to finance future acquisitions of equity interests in Columbia OpCo or enter into any other transaction with a party other than CPG and its Affiliates shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise, whether or not such determination was influenced solely or in part by consideration of any adverse impact on CPG.

Section 7.2 Replacement of Fiduciary Duties. Notwithstanding any other provision of this Agreement, to the extent that, at law or in equity, the General Partner or any other Indemnitee would have duties (including fiduciary duties) to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, all such duties (including fiduciary duties) are hereby eliminated, to the fullest extent permitted by law, and replaced with the duties expressly set forth herein. The elimination of duties (including fiduciary duties) and replacement thereof with the duties expressly set forth herein are approved by the Partnership, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement.

Section 7.3 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The

 

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General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Partner.

Section 7.4 Restrictions on the General Partner’s Authority. Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.5 Reimbursement of the General Partner.

(a) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person (including Affiliates of the General Partner) to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.5 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(b) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment for such management fee of such management fee or fees exceeds the amount of such fee or fees.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests or Derivative Instruments), or cause the Partnership to issue Partnership Interests or Derivative Instruments in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, any Group Member or their Affiliates, or any of them, in each case for the benefit of employees, officers, consultants and directors of the General Partner or its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are

 

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obligated to provide to any employees, officers, consultants and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.5(a). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.5(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.6 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership, shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (i) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (ii) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (iii) the direct or indirect provision of management, advisory, and administrative services to its Affiliates or to other Persons.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member. No such business interest or activity shall constitute a breach of this Agreement, any fiduciary or other duty existing at law, in equity or otherwise, or obligation of any type whatsoever to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement.

(c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to any Group Member, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for breach of any fiduciary or other duty existing at law, in equity or otherwise by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires such opportunity for itself, directs such opportunity to another Person or does not communicate such opportunity or information to any Group Member.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise expressly provided in Section 7.11, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Interests acquired by them.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising

 

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from any and all threatened pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in Bad Faith or engaged in willful misconduct or fraud or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by an Indemnitee with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

 

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(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Limitation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, any Group Member Agreement, or under the Delaware Act or any other law, rule or regulation or at equity, no Indemnitee shall be liable for monetary damages or otherwise to the Partnership, to another Partner, to any other Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, for losses sustained or liabilities incurred, of any kind or character, as a result of its or any of any other Indemnitee’s determinations, act(s) or omission(s) in their capacities as Indemnitees; provided, however, that an Indemnitee shall be liable for losses or liabilities sustained or incurred by the Partnership, the other Partners, any other Persons who acquire an interest in a Partnership Interest or any other Person bound by this Agreement, if it is determined by a final and non-appealable judgment entered by a court of competent jurisdiction that such losses or liabilities were the result of the conduct of that Indemnitee engaged in by it in Bad Faith or engaged in willful misconduct or fraud or with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner if such appointment was not made in Bad Faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership, to the Partners, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership, to any Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for its reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

 

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Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Whenever the General Partner, acting in its capacity as the general partner of the Partnership, or the Board of Directors or any committee of the Board of Directors (including the Conflicts Committee) or any Affiliates of the General Partner cause the General Partner to make a determination or take or omit to take any action in such capacity, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then, unless another lesser standard is provided for in this Agreement, the General Partner, the Board of Directors, such committee or such Affiliates, shall not make such determination, or take or omit to take such action, in Bad Faith. The foregoing and other lesser standards provided for in this Agreement are the sole and exclusive standards governing any such determinations, actions and omissions of the General Partner, the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) and any Affiliate of the General Partner and no such Person shall be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard (all of which duties, obligations and standards are hereby waived and disclaimed), under this Agreement any Group Member Agreement or any other agreement contemplated hereby, or under the Delaware Act or any other law, rule or regulation or at equity. Any such determination, action or omission by the General Partner, the Board of Directors of the General Partner or any committee thereof (including the Conflicts Committee) or of any Affiliates of the General Partner, will for all purposes be presumed to have been in Good Faith. In any proceeding brought by or on behalf of the Partnership, any Limited Partner, or any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement, challenging such determination, act or omission, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or omission was not in Good Faith.

(b) Whenever the General Partner makes a determination or takes or omits to take any action, or any of its Affiliates causes it to do so, not acting in its capacity as the general partner of the Partnership, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or omit to take such action free of any fiduciary duty or duty of Good Faith, or other duty or obligation existing at law, in equity or otherwise whatsoever to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in Good Faith or pursuant to any fiduciary or other duty or standard imposed by this Agreement, any Group Member Agreement or any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(c) For purposes of Sections 7.9(a) and (b) of this Agreement, “acting in its capacity as the general partner of the Partnership” means and is solely limited to, the General Partner exercising its authority as a general partner under this Agreement, other than when it is “acting in its individual capacity.” For purposes of this Agreement, “acting in its individual capacity” means: (i) any action by the General Partner or its Affiliates other than through the exercise of the General Partner of its authority as a general partner under this Agreement; and (ii) any action or inaction by the General Partner by the exercise (or failure to exercise) of its rights, powers or authority under this Agreement that are modified by: (A) the phrase “at the option of the General Partner,” (B) the phrase “in its sole discretion” or “in its discretion” or (iii) some variation of the phrases set forth in clauses (i) and (ii). For the avoidance of doubt, whenever the General Partner votes, acquires Partnership Interests or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be and be deemed to be “acting in its individual capacity.”

(d) The General Partner may in its discretion submit any determination, action or omission that would otherwise be decided by the General Partner pursuant to Section 7.9(a) (i) for Special Approval or (ii) for approval

 

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by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner or its Affiliates). If the General Partner does not submit the determination, action or omission as provided in either clauses (i) or (ii) in the preceding sentence, then any such determination, action or omission shall be governed by Section 7.9(a) above. The General Partner is not required in connection with its resolution of any conflict of interest to seek Special Approval or Unitholder approval of such resolution and may determine not to do so in its sole discretion. If any determination, action or omission: (A) receives approval of a majority of the Common Units (excluding Common Units owned by the General Partner or its Affiliates), then such determination, action or omission shall be conclusively deemed to be approved by the Partnership, all the Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any fiduciary or other duty or obligation existing at law, in equity.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates or any other Indemnitee shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts or transactions shall be in its sole discretion.

(f) The Partners and each Person who acquires an interest in a Partnership Interest or is otherwise bound by this Agreement hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

(g) For the avoidance of doubt, whenever the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee), the officers of the General Partner or any Affiliates of the General Partner make a determination on behalf of the General Partner, or cause the General Partner to take or omit to take any action, whether in the General Partner’s capacity as the general partner of the Partnership or in its individual capacity, the standards of care applicable to the General Partner shall apply to such Persons, and such Persons shall be entitled to all benefits and rights of the General Partner hereunder, including waivers and modifications of duties, protections and presumptions, as if such Persons were the General Partner hereunder.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in Good Faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its or the Partnership’s duly authorized officers, a duly appointed attorney or attorneys-in-fact.

 

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Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests; provided that, except as permitted pursuant to Section 4.10 or as approved by the Conflicts Committee, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as any Partnership Interests are held by any Group Member, such Partnership Interests shall not be entitled to any vote and shall not be considered to be Outstanding.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any of its Affiliates (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder”) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, however, that the Partnership shall not be required to effect more than two registrations pursuant to this Section 7.12(a) in any twelve-month period; and provided further, however, that if the General Partner determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such

 

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offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or issuer free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the

 

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proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

(g) The Partnership may enter into separate registration rights agreements with the General Partner or any of its Affiliates.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available to such Person or Partner to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

 

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(a) As soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(b) As soon as practicable, but in no event later than 50 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or year that it is required by law to adopt, from time to time, as determined by the General Partner. If the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest Closing Price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.

 

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(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings. Each Partner agrees that notice of or updates regarding tax controversies shall be deemed conclusively to have been given or made by the Tax Matters Partner if the Partnership has either (i) filed the information for which notice is required with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such information is publicly available on such system or (ii) made the information for which notice is required available on any publicly available website maintained by the Partnership, whether or not such Partner remains a Partner in the Partnership at the time such information is made publicly available.

Section 9.4 Withholding; Tax Payments.

(a) The General Partner may treat taxes paid by the Partnership on behalf of, all or less than all of the Partners, either as a distribution of cash to such Partners or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner.

(b) Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests or the issuance of any Limited Partner Interests in accordance herewith, and except as provided in Section 4.8, each transferee of, or other recipient, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer or issuance is reflected in the books and records of the Partnership, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) shall become the Record Holder of the Limited Partner Interests so transferred or issued, (iv) represents that the transferee or other recipient has the capacity, power and authority to enter into this Agreement and (v) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an

 

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amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Exhibit A.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

 

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(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the U.S. Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the U.S. Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) if the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; and (D) if the General Partner is a natural person, his death or adjudication of incompetency.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B) or (C) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on                     , 2025, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on                     , 2025, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), a Unit Majority may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as

 

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successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Unitholders holding at least 66 2/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the Outstanding Common Units, voting as a class, and a majority of the Outstanding Subordinated Units, voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates’ Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.5, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

 

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For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (and its Affiliates, if applicable) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (and its Affiliates, if applicable) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (i) the Percentage Interest of the General Partner Interest of the Departing General Partner by (ii) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Conversion of Subordinated Units. Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist, the Subordinated Units held by any Person will immediately and automatically convert into Common Units on a one-for-one basis, provided (i) neither such Person nor any of its Affiliates voted any of its Units in favor of the removal and (ii) such Person is not an Affiliate of the successor General Partner; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x), Section 6.7(b) and Section 6.7(c).

 

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Section 11.5 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, the Partnership shall not be dissolved and such successor General Partner is hereby authorized to, and shall, continue the business of the Partnership. Subject to Section 12.2, the Partnership shall dissolve, and its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and such successor is admitted to the Partnership pursuant to this Agreement;

(b) an election to dissolve the Partnership by the General Partner that is approved by a Unit Majority;

(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an

 

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Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the

 

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Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity

 

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of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests and Derivative Instruments pursuant to Section 5.6;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or 7.1(a);

(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion. An amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or 13.3, a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have

 

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notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no provision of this Agreement (other than Section 11.2 or Section 13.4) that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) or requires a vote or approval of Partners (or a subset of Partners) holding a specified Percentage Interest to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing or increasing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable, or the affirmative vote of Partners whose aggregate Percentage Interests constitute not less than the voting requirement sought to be reduced or increased, as applicable.

(b) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3 or Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Percentage Interests of all Limited Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Limited Partners.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 25% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner

 

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one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the meeting is proposed. No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (i) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (ii) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Postponement and Adjournment. Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless such postponement shall be for more than 45 days. Any meeting of Limited Partners may be adjourned by the General Partner one or more times for any reason, including the failure of a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No Limited Partner vote shall be required for any adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

 

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Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transaction of business at any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting. The holders of a majority, by Percentage Interest, of Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater Percentage Interest, in which case the quorum shall be such greater Percentage Interest. At any meeting of the Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of holders of Partnership Interests that, in the aggregate, represent a majority of the Percentage Interest of those present in person or by proxy at such meeting shall be deemed to constitute the act of all Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the holders of Partnership Interests that in the aggregate represent at least such greater or different percentage shall be required; provided, however, that if, as a matter of law or provision of this Agreement, approval by plurality vote of Partners (or any class thereof) is required to approve any action, no minimum quorum shall be required. The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by holders of the required Percentage Interest specified in this Agreement.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner), as the case may be, that would be necessary to authorize or take such action at a meeting at which all the Limited Partners entitled to vote at such meeting were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall

 

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govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

Section 13.13 Voting of Incentive Distribution Rights.

(a) For so long as a majority of the Incentive Distribution Rights are held by the General Partner and its Affiliates, the holders of the Incentive Distribution Rights shall not be entitled to vote such Incentive Distribution Rights on any Partnership matter except as may otherwise be required by law and the holders of the Incentive Distribution Rights, in their capacity as such, shall be deemed to have approved any matter approved by the General Partner.

(b) If less than a majority of the Incentive Distribution Rights are held by the General Partner and its Affiliates, the Incentive Distribution Rights will be entitled to vote on all matters submitted to a vote of Unitholders, other than amendments and other matters that the General Partner determines do not adversely affect the holders of the Incentive Distribution Rights as a whole in any material respect. On any matter in which the holders of Incentive Distribution Rights are entitled to vote, such holders will vote together with the Subordinated Units, prior to the end of the Subordination Period, or together with the Common Units, thereafter, in either case as a single class except as otherwise required by Section 13.3(c), and such Incentive Distribution Rights shall be treated in all respects as Subordinated Units or Common Units, as applicable, when sending

 

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notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement. The relative voting power of the Incentive Distribution Rights and the Subordinated Units or Common Units, as applicable, will be set in the same proportion as cumulative cash distributions, if any, in respect of the Incentive Distribution Rights for the four consecutive Quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of Units for such four Quarters.

(c) In connection with any equity financing, or anticipated equity financing, by the Partnership of an Expansion Capital Expenditure, the General Partner may, without the approval of the holders of the Incentive Distribution Rights, temporarily or permanently reduce the amount of Incentive Distributions that would otherwise be distributed to such holders, provided that in the judgment of the General Partner, such reduction will be in the long-term best interest of such holders.

ARTICLE XIV

MERGER OR CONSOLIDATION

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the U.S., pursuant to a written plan of merger or consolidation (“Merger Agreement”) in accordance with this Article XIV.

Section 14.2 Procedure for Merger or Consolidation.

(a) Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner, in declining to consent to a merger or consolidation, may act in its sole discretion.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (A) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, then the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon

 

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conversion of their interests, securities or rights, and (B) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, certificate of formation or limited liability company agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain and stated in the certificate of merger); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d) and 14.3(e), the General Partner, upon its approval of the Merger Agreement shall direct that the Merger Agreement and the merger or consolidation contemplated thereby, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) and 14.3(e), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger or conveyance, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any

 

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Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger or Consolidation.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

 

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(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be filed and distributed as may be required by the Commission or any National Securities Exchange on which such Limited Partner Interests are listed. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record

 

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books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests.

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class U.S. mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the U.S. Postal Service (or other physical mail delivery mail service outside the U.S.), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

 

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Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereof.

Section 16.9 Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claim, suit, action or proceeding;

 

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(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding;

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in this clause (v) shall affect or limit any right to serve process in any other manner permitted by law; and

(vi) IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING; and

(vii) agrees that if such Partner or Person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought in any such claim, suit, action or proceeding, then such Partner or Person shall be obligated to reimburse the Partnership and its Affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Section 16.10 Invalidity of Provisions. If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and/or parts thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.11 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile Signatures. The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

GENERAL PARTNER:
CPP GP LLC

By:

 

 

Name:  

 

Title:

 

 

ORGANIZATIONAL LIMITED PARTNER:
Columbia Energy Group

By:

 

 

Name:    

Title:

 

 

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Appendix B

ELIGIBLE HOLDER STATUS

“Ineligible Holders” are limited partners, or types of limited partners, whose or whose owners’, in the determination of our general partner with the advice of counsel, (i) U.S. federal income tax status (or lack of proof thereof) creates or is reasonably likely to create a substantial risk of an adverse effect on the rates that can be charged to our customers by us or our subsidiaries, or (ii) nationality, citizenship, or other related status creates a substantial risk of cancellation or forfeiture of any property in which we have an interest. The following is a list of various types of individuals and entities that are categorized and identified as Eligible Holder, potentially Eligible Holder or Ineligible Holder. Our general partner may change its determination of the types of entities that constitute Ineligible Holders from time to time.

Eligible Holders

The following are currently considered Eligible Holders:

 

   

Individuals (U.S. or non-U.S.)

 

   

C corporations (U.S. or non-U.S.)

 

   

Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

 

   

S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

 

   

Mutual Funds

Potentially Eligible Holders

The following are currently considered Eligible Holders, unless the information in parenthesis applies:

 

   

S corporations (unless they have ESOP shareholders*)

 

   

Partnerships (unless its partners include real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders* or other partnerships with such partners)

 

   

Trusts (unless beneficiaries are not subject to tax)

Ineligible Holders

The following are currently considered Ineligible Holders:

 

   

REITs

 

   

Governmental entities and agencies

 

   

S corporations with ESOP shareholders *

 

 

(*)  “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

 

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Appendix C

GLOSSARY OF TERMS

Adjusted EBITDA: A supplemental non-GAAP financial measure defined by us as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

AFUDC: Allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation.

BBtu: One billion British Thermal Units.

condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

CCRM: Capital Cost Recovery Mechanism

end-user markets: The ultimate users and consumers of transported energy products.

FERC: Federal Energy Regulatory Commission.

GAAP: Generally accepted accounting principles.

HP: Horsepower.

local distribution company or LDC: LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.

LNG: Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

Mcf: One thousand cubic feet.

MMcf: One million cubic feet.

NGA: Natural Gas Act of 1938.

NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

OCI: Other Comprehensive Income.

park and loan services: Those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

 

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PHMSA: Pipeline and Hazardous Materials Safety Administration.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

shale gas: Natural gas produced from organic (black) shale formations.

TBtu: One trillion British Thermal Units.

Tcf: One trillion cubic feet.

throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

 

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LOGO

Columbia Pipeline Partners LP

40,000,000 Common Units

Representing Limited Partner Interests

 

 

Prospectus

                          , 2015

 

 

Joint Book-Runners

Barclays

Citigroup

BofA Merrill Lynch

Goldman, Sachs & Co.

J.P. Morgan

Morgan Stanley

Wells Fargo Securities

Co-Managers

BNP PARIBAS

Credit Suisse

RBC Capital Markets

Fifth Third Securities

KeyBanc Capital Markets

MUFG

Mizuho Securities

Scotia Howard Weil

Huntington Investment Company

Through and including             , 2015 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


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PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT

 

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than the underwriting discount) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the New York Stock Exchange listing fee the amounts set forth below are estimates.

 

SEC registration fee

   $ 122,329   

FINRA filing fee

     145,400   

Printing and engraving expenses

     700,000   

Fees and expenses of legal counsel

     2,300,000   

Accounting fees and expenses

     1,150,000   

Transfer agent and registrar fees

     5,000   

New York Stock Exchange listing fee

     178,000   

Miscellaneous

     209,271   
  

 

 

 

Total

   $ 4,810,000   
  

 

 

 

 

* To be completed by amendment

 

ITEM 14. INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of NiSource Inc. and our general partner, their officers and directors, and any person who controls NiSource Inc. and our general partner, including indemnification for liabilities under the Securities Act.

 

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

There have been no sales of unregistered securities within the past three years.

 

ITEM 16. EXHIBITS.

See the Index to Exhibits on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Index to Exhibits is incorporated herein by reference.

 

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ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions General Partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to General Partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on January 26, 2015.

 

Columbia Pipeline Partners LP

By:

 

CPP GP LLC, its general partner

 

By:

 

/s/ Robert C. Skaggs, Jr.

Name:

 

Robert C. Skaggs, Jr.

Title:

 

Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature

  

Title

  Date

/s/    Robert C. Skaggs, Jr.        

Robert C. Skaggs, Jr.

  

Chief Executive Officer (Principal Executive Officer)

  January 26, 2015

/s/    Stephen P. Smith        

Stephen P. Smith

  

Director, Chief Financial Officer and Chief Accounting Officer (Principal Financial Officer and Principal Accounting Officer)

  January 26, 2015

 

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INDEX TO EXHIBITS

 

Exhibit
Number

      

Description

     1.1†      Form of Underwriting Agreement
  3.1†      Certificate of Limited Partnership of NiSource Energy Partners, L.P.
     3.2†      Certificate of Amendment to Certificate of Limited Partnership of NiSource Energy Partners, L.P.
     3.3†      Form of Amended and Restated Limited Partnership Agreement of Columbia Pipeline Partners LP (included as Appendix A in the prospectus included in this Registration Statement)
     4.1†      Form of Registration Rights Agreement
  5.1*      Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
     8.1†      Opinion of Vinson & Elkins L.L.P. relating to tax matters
   10.1†      Form of Contribution, Conveyance and Assumption Agreement
   10.2†      Form of Omnibus Agreement
   10.3†      Form of Columbia Pipeline Partners LP Long-Term Incentive Plan
   10.4†      Form of Service Agreement
   10.5†      System Money Pool Agreement, dated as of November 1, 2014, by and among Columbia Pipeline Group, Inc., NiSource Finance Corp., NiSource Corporate Services Company, as administrative agent, and the direct and indirect subsidiaries of Columbia Pipeline Group, Inc.
   10.6†      Revolving Credit Agreement, dated as of December 5, 2014, by and among Columbia Pipeline Partners LP, as Borrower, NiSource Inc., Columbia Pipeline Group, Inc., Columbia Energy Group, CPG OpCo LP, CPG OpCo GP LLC, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent, The Bank of Tokyo-Mitsubishi UFJ, LTD, as Syndication Agent
   10.7†      Form of Tax Sharing Agreement
   10.8†      Form of Trademark License Agreement
    10.9†      Form of Amended and Restated Limited Partnership Agreement of CPG OpCo LP
    10.10†      Form of Columbia Pipeline Partners LP Phantom Unit Agreement
  21.1†      List of Subsidiaries of Columbia Pipeline Partners LP
  23.1*      Consent of Deloitte & Touche LLP
  23.2*      Consent of Deloitte & Touche LLP
  23.3*      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  23.4†      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
  24.1†      Powers of Attorney (contained on signature page)
99.1†      Consent of Thomas W. Hofmann, as director nominee
99.2†      Consent of Robert C. Skaggs, Jr., as director nominee
99.3†      Consent of Glenn L. Kettering, as director nominee
99.4†      Consent of Robert E. Smith, as director nominee
99.5†      Consent of Stanley G. Chapman, III, as director nominee

 

* Provided herewith.
** To be provided by amendment.
Previously filed.

 

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