UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ                     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

¨                    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 001-36835

Columbia Pipeline Partners LP

(Exact name of registrant as specified in its charter)

 

Delaware		51-0658510
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
5151 San Felipe St., Suite 2500 Houston, Texas		77056
(Address of principal executive offices)		(Zip Code)

(713) 386-3701

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class		Name of each exchange on which registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:        None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  ¨    No  þ*

*We completed our initial public offering on February 11, 2015 and, accordingly, have not been subject to the reporting requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934 as amended.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in of this Form 10-K or any amendment to this Form 10-K.    þ

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12-b-2 of the Exchange Act.

 

Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer þ		Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ

As of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on February 6, 2015.

At February 18, 2015, there were 53,833,107 Common Units and 46,811,398 Subordinated Units outstanding.

Documents Incorporated by Reference

None.

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CONTENTS

 

				Page No.
Defined Terms				3
Part I				6
Items 1 and 2.		Business and Properties		6
Item 1A.		Risk Factors		16
Item 1B.		Unresolved Staff Comments		43
Item 3.		Legal Proceedings		44
Item 4.		Mine Safety Disclosures		44
Part II				45
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6.		Selected Financial Data		47
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		50
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		69
Item 8.		Financial Statements and Supplementary Data		70
Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		110
Item 9A.		Controls and Procedures		110
Item 9B.		Other Information		110
Part III				111
Item 10.		Directors, Executive Officers and Corporate Governance		111
Item 11.		Executive Compensation		115
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		117
Item 13.		Certain Relationships and Related Transactions, and Director Independence		120
Item 14.		Principal Accountant Fees and Services		126
Part IV				127
Item 15.		Exhibits and Financial Statement Schedules		127
Signatures				128
Exhibit Index				129

 

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Columbia Pipeline Partners LP

 

DEFINED TERMS

The following is a list of abbreviations or acronyms that are used in this report:

 

Affiliates of Columbia Pipeline Partners LP
CEG		Columbia Energy Group
CEVCO		Columbia Energy Ventures, LLC
CNS Microwave		CNS Microwave, LLC
Columbia Gulf		Columbia Gulf Transmission, LLC
Columbia Gas Transmission		Columbia Gas Transmission, LLC
Columbia Midstream		Columbia Midstream Group, LLC
Columbia OpCo		CPG OpCo LP
CPG		Columbia Pipeline Group Inc.
Hardy Storage		Hardy Storage Company, LLC
Millennium Pipeline		Millennium Pipeline Company, L.L.C.
NiSource		NiSource Inc.
NiSource Corporate Services		NiSource Corporate Services Company
NiSource Finance		NiSource Finance Corp.
Pennant		Pennant Midstream, LLC
Abbreviations and Defined 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 method prescribed 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.
AOC		Administrative Order on Consent
Btu		British Thermal Unit
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
DOT		Department of Transportation
Dth/d		Dekatherms per day
end-user markets		The ultimate users and consumers of transported energy products
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles
Hilcorp		Hilcorp Energy Company
HP		Horsepower

 

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Columbia Pipeline Partners LP

 

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
MMBtu		One million British Thermal Units
MMDth		One million dekatherms
MMDth/d		One million dekatherms per day
NGA		Natural Gas Act of 1938
NGL		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 (Loss)
park and loan services		Those services pursuant to which customers receive the right for a fee to store natural gas in (park), or borrow gas from (loan), our facilities on a contractual basis
play		A proven geological formation that contains commercial amounts of hydrocarbons
PHMSA		Pipeline and Hazardous Materials Safety Administration
Piedmont		Piedmont Natural Gas Company, Inc.
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.
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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Columbia Pipeline Partners LP

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Some of the information in this report 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 report. 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:

 

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changes in general economic conditions;

 

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competitive conditions in our industry;

 

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actions taken by third-party operators, processors and transporters;

 

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the demand for natural gas storage and transportation services;

 

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our ability to successfully implement our business plan;

 

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our ability to complete internal growth projects on time and on budget;

 

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the price and availability of debt and equity financing;

 

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the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

 

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competition from the same and alternative energy sources;

 

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energy efficiency and technology trends;

 

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operating hazards and other risks incidental to transporting, storing and gathering natural gas;

 

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natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

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interest rates;

 

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labor relations;

 

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large customer defaults;

 

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changes in the availability and cost of capital;

 

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changes in tax status;

 

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the effects of existing and future laws and governmental regulations;

 

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the effects of future litigation; and

 

•

certain factors discussed elsewhere in this report.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please see Item 1A “Risk Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

 

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Columbia Pipeline Partners LP

 

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Organizational History

Unless the context otherwise requires, references in this annual report on Form 10-K to the “Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context (periods prior to February 11, 2015), 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 to “Columbia Pipeline Partners,” “we,” “our,” “us” and the “Partnership” or like terms when used in the present tense or prospectively (after February 11, 2015), refer to Columbia Pipeline Partners LP and its subsidiaries. We refer to our general partner, CPG GP LLC, as our “general partner” and refer to NiSource Inc. and its subsidiaries other than us and our general partner as “NiSource.” References in this report to “Columbia OpCo” refer to CPG OpCo LP and its subsidiaries. References in this report 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. After the closing of our initial public offering on February 11, 2015, we own a 15.7% controlling interest in Columbia OpCo, and CEG owns an 84.3% non-controlling interest in Columbia OpCo. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect CEG’s 84.3% non-controlling interest in Columbia OpCo.

We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource. We were formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets. On February 11, 2015, we completed our initial public offering (the “Offering”) of 53,833,107 common units representing limited partner interests. Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “CPPL.” Please see Note 1 of Notes to Combined Financial Statements for further discussion of the Offering.

Spin-off of Columbia Pipeline Group

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 Columbia Pipeline Group, 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 CPG will receive an investment grade rating. In the event the spin-off does occur, CPG will continue to indirectly own our general partner, 84.3% 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 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 CPG and CEG or as a result of recruitment and retention employee issues, increased costs associated with CPG 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 CPG may enter into with NiSource in connection with the spin-off.

Partnership Structure and 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 the sole member of our general partner, CEG has the right to appoint all of the members of the board of directors of our general partner.

 

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Columbia Pipeline Partners LP

 

The following chart shows our organization and ownership structure as of February 11, 2015. The ownership percentages referred to below illustrate the relationships among us, Columbia OpCo, our general partner, CEG, NiSource and its affiliates:

 

As part of the transactions in connection with the Offering, we acquired the non-economic general partner interest in Columbia OpCo as well as a 15.7% limited partner interest in Columbia OpCo, a Delaware limited partnership that owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of interstate pipelines and operates an underground natural gas storage systems with approximately 300 MMDth of working gas capacity. Through its subsidiaries, Columbia Gas Transmission, Columbia Gulf and Columbia Midstream, Columbia OpCo owns and operates an interstate pipeline network extending from the Gulf of Mexico to New York and the eastern seaboard. Together, these companies serve customers in 15 northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia.

 

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Columbia Pipeline Partners LP

 

Columbia OpCo continues to develop a range of growth initiatives, including mineral leasing and optimization, midstream projects and traditional pipeline expansion opportunities that leverage strategically positioned pipeline and storage assets. A number of Columbia OpCo’s new growth projects are designed to support increasing Marcellus and Utica shale production, while its operations also have continued to grow and adapt its system to provide critical transportation and storage services to markets across its high-demand service territory.

Business Segment

Our operations comprise one reportable segment containing our portfolio of pipelines, storage and related midstream assets. Please see Note 16, “Segments of Business” in Item 8, Financial Statements and Supplementary Data for further discussion regarding our segment.

Description of Businesses

Interstate Pipeline and Storage Assets. Through our ownership interests in Columbia OpCo, we own the FERC-regulated natural gas transportation and storage assets described below.

Columbia Gas Transmission. Columbia Gas Transmission owns and operates a FERC-regulated interstate natural gas transportation pipeline and storage system, which 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’s pipeline system consists of 11,395 miles of natural gas transmission pipeline. It has a transportation capacity of approximately 10 MMDth/d, transports an average of approximately 3.8 MMDth/d and serves communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission owns and leases approximately 819,000 acres of underground storage, 3,436 storage wells, which includes 34 storage fields in four states with approximately 622 MMDth in total operational capacity, with approximately 290 MMDth of working gas capacity.

Columbia Gulf. The Columbia Gulf pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of 3,341 miles of natural gas transmission pipeline. The 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 25 interstate and 7 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. In addition, Columbia Gulf recently reconfigured its system so that it can reverse flow on one of its three pipelines. Flows on the other two pipelines will be reversed as part of expansion projects that are underway.

Millennium Pipeline Joint Venture. We own 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.

 

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Columbia Pipeline Partners LP

 

Hardy Storage Joint Venture. We own 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 and the ability to deliver 176,000 Dth/d. 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 gathering, processing and other assets described below.

Columbia Midstream. Columbia Midstream provides natural gas producer services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin. Columbia Midstream owns 103 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and also owns a 50% ownership interest in Pennant Midstream LLC, which owns approximately 80 miles of wet natural gas gathering pipeline infrastructure, a cryogenic processing plant and an NGL pipeline. Columbia Midstream supports the growing production in the Utica and Marcellus resource plays.

CEVCO. CEVCO manages the Columbia OpCo’s mineral rights positions in the Marcellus and Utica shale areas. CEVCO owns production rights to approximately 460,000 acres and has sub-leased the production rights in four storage fields and has also contributed its production rights in one other field. CEVCO has entered into multiple transactions to develop its minerals position and as a result receives revenue through working interests and/or overriding royalty interests.

Business Strategy

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 revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities. 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 organic growth projects, 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 84.3% 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 organic growth projects that we expect Columbia OpCo to complete will be backed 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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Columbia Pipeline Partners LP

 

Current System Expansion Opportunities

The unique location and capabilities of our pipeline assets place us in a strategically advantageous position to continue to capitalize on expected growth in production from the Marcellus and Utica shales. To that end, we are currently pursuing the following significant expansion projects:

 

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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.

 

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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, Pennsylvania and Smithfield, Pennsylvania areas on the Columbia Gas Transmission system. We invested approximately $87 million in new pipeline and compression, which provides 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.

 

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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.

 

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Line 1570 Expansion. We replaced approximately 19 miles of existing 20-inch pipeline with a 24-inch pipeline and added 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.

 

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West Side Expansion (Columbia Gulf—Bi-Directional). Under this project we invested 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.

 

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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.

 

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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 approximately 10-mile 20-inch pipeline and compression facilities will support Marcellus shale production in western Pennsylvania. Approximately 50% of the increased capacity generated by the project is 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.

 

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East Side Expansion. We have received 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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Washington County Gathering. A larger 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.

 

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Columbia Pipeline Partners LP

 

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.

 

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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 will be placed in service by the end of the second quarter of 2016.

 

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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 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 1.5 MMDth/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 $1.4 billion in this project.

 

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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. The project also includes the creation of a new compressor station. 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 $383 million on the Rayne XPress project to modify existing facilities and to add new compression.

 

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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.

 

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WB XPress. We expect to invest approximately $870 million in this project to expand the WB system through looping and added compression in order to transport 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. 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, which began in 2013, to modernize our Columbia Gas Transmission 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 2014, we completed nearly 40 individual projects bringing the total program investment to approximately $618 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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Columbia Pipeline Partners LP

 

Regulatory Matters

Pipeline Safety and Maintenance. Our pipelines used for gathering and transporting natural gas and NGLs are subject to regulation by the PHMSA of the DOT pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”). Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thicknesses, design pressures, maximum 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. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. We believe that our pipeline operations are in material compliance with applicable NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.

These pipeline safety laws were amended in January 2012, when President Obama signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), which requires increased safety measures for natural gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directed the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, pipeline material strength testing, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmissions 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 from $1.0 million to $2.0 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 PHMSA regulations thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any of which could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

In addition, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty or material cost in complying with applicable intrastate pipeline safety laws and regulations in 2015. Our pipelines have operations and maintenance plans designed to keep the facilities in compliance with pipeline safety requirements. We, or the entities in which we own an interest, inspect our pipelines regularly in material compliance with applicable state and federal maintenance requirements. Nonetheless, the adoption of new or amended regulations by states in which we operate that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and similarly situated midstream operators.

Environmental and Occupational Safety and Health. Our pipeline, storage and related midstream operations are subject to stringent and complex federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. The more significant of these existing environmental and occupational safety and health laws and regulations, as amended from time to time, include the following:

 

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The federal Clean Air Act (“CAA”) and comparable state laws, which restrict the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements. Our natural gas transmission and storage assets are considered potential sources of air emissions subject to permitting obligations for existing, modified or new sources of air emissions and compliance with which could result in potential delays in the development of projects and in the incurrence of capital expenditures for air pollution control equipment or other air emissions-related issues.

 

 

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Columbia Pipeline Partners LP

 

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The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) and comparable state laws, which impose liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred. Under CERCLA, responsible parties, including current and past owners or operators of a site where a hazardous substance release occurred and entities who disposed or arranged for the disposal of a hazardous substance released at the site may be held liable for the costs of cleaning up the hazardous substances released, for damages to natural resources and for the costs of certain health studies. We generate materials in the course of our operations that may be regulated as hazardous substances.

 

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The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, which govern the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes.

 

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The U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (“CWA”), and analogous state laws that regulate discharges of pollutants from facilities to state and federal waters. Among other things, the CWA may require permits for facilities that discharge wastewaters or dredge and fill material into regulated waters, including wetlands; spill prevention, control and countermeasure plans requiring appropriate berms to help prevent contamination of regulated waters in the event of a hydrocarbon release; and individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities.

 

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The U.S. Oil Pollution Act of 1990 (“OPA”), which amends the CWA and subjects certain owners and operators, including owners and operators of pipelines and other onshore facilities, to liability for removal costs and damages arising from an oil spill in waters of the United States.

 

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The Toxic Substances Control Act and any comparable state laws, which require that polychlorinated biphenyl (“PCB”) contaminated materials be managed in accordance with a comprehensive regulatory regime. We are currently remediating PCBs at certain gas transmission facilities where PCBs were released into the environment.

 

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The U.S. Occupational Safety and Health Act (“OSHA”) and analogous state laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

 

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The Endangered Species Act and comparable state statutes, which restrict activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Any expansion projects pursued by us must take into consideration the adverse impact of such projects on protected species and habitats.

 

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The National Environmental Policy Act, which requires federal agencies to consider potential environmental effects in their decisions, including site approvals. Many of our capital projects require federal agency review, and therefore the environmental effects of proposed projects are a factor in determining whether we will be authorized to complete those projects.

These laws and regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. See Risk Factors under Item 1A of this Form 10-K for further discussion on hydraulic fracturing, climate change, and regulations relating to environmental protection. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as new standards, such as air emission standards and water quality standards, continue to evolve.

 

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Columbia Pipeline Partners LP

 

We have made and will continue to make operating and capital expenditures, some of which may be material, to comply with environmental and occupational safety and health laws and regulations. These are necessary business costs in our operations and in the pipeline transportation and storage industry. Although we are not fully insured against all environmental and occupational safety and health risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe is sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental and occupational safety and health laws and regulations, as well as claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, including administrative, civil, and criminal penalties. We believe that we are in material compliance with existing environmental and occupational safety and health regulations. Further, we believe that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on our business, financial condition, results of operations, or cash flows, but new or more stringently applied existing laws and regulations could increase the cost of doing business, and such increases could be material.

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.

Our interstate natural gas transportation and storage system operations are regulated by the FERC under the NGA and the Natural Gas Policy Act of 1978 (“NGPA”), and the FERC’s regulations under those statutes. The FERC regulatory policies govern the rates and services that each FERC-regulated pipeline is permitted to charge customers for interstate transportation and storage of natural gas. 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. In addition, the FERC also regulates the construction of U.S. interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. 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. The FERC may propose and implement new rules and regulations which may affect the business, financial condition and results of operations of our interstate natural gas transmission and storage companies.

Pursuant to Section 1(b) of the NGA, our natural gas gathering facilities are exempt 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. We cannot predict what effect, if any, a change in the regulation of our gathering facilities 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.

Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required construction 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.

Competition. Our pipeline systems compete primarily with other interstate and intrastate pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

 

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Columbia Pipeline Partners LP

 

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.

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.

Customers and Contracts

Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. 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. Transportation and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs. We also provide interruptible transportation and storage services where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated market rates for this interruptible service. Columbia Gas of Ohio, an affiliated party, and Washington Gas and Light accounted for approximately 13% and 9% of our contracted revenues, respectively, for the year ended December 31, 2014. Please see Note 18, “Concentration of Credit Risk” in Item 8, Financial Statements and Supplementary Data for further discussion.

Our customers for our midstream operations consist of natural gas producers with whom we primarily have long-term, fee-based gas gathering agreements, with terms ranging from 10 to 15 years typically with minimum volume commitments.

Employees

Neither we nor Columbia OpCo have employees. As of December 31, 2014, NiSource had 8,982 employees, of which 1,488 were involved in the business of our predecessor. Of these 1,488 employees, 244 are covered by collective bargaining agreements that expire in 2016 and 2017. We believe that NiSource’s relationship with the local union officials and bargaining committees is open and positive.

For a listing of certain subsidiaries of the Partnership refer to Exhibit 21.1.

Additional Information

We were formed on December 5, 2007 as a Delaware master limited partnership. Our principal executive offices are located at 5151 San Felipe St., Suite 2500, Houston, Texas 77056, and our telephone number is 713-386-3701. We electronically file various reports with the Securities and Exchange Commission (“SEC”), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at http://www.columbiapipelinepartners.com. These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.

 

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Columbia Pipeline Partners LP

 

ITEM 1A. RISK FACTORS

There are many factors that could have a material adverse effect on the Partnership’s operating results, financial condition and cash flows. New risks may emerge at any time, and the Partnership cannot predict those risks or estimate the extent to which they may affect financial performance. Each of the risks described below could adversely impact the value of the Partnership’s 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.

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 $16.9 million per quarter, or $67.4 million per year, based on the number of common and subordinated units outstanding as of February 11, 2015.

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:

 

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

 

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

 

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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;

 

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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;

 

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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;

 

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

 

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the creditworthiness of our customers;

 

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

 

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

 

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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;

 

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

 

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

 

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

 

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

 

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

 

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Columbia Pipeline Partners LP

 

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

 

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

 

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construction costs;

 

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

 

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

 

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

 

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

 

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the amount of cash reserves established by our general partner.

Columbia OpCo will be a restricted subsidiary and a guarantor under CPG’s credit facility and, if requested by CPG, will guarantee future CPG 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 is generated from cash distributions from Columbia OpCo. In connection with the spin-off, CPG’s credit facility will become effective and is expected to have customary covenants and restrictions on CPG and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facility. In addition, CPG expects to issue a significant amount of new senior indebtedness and use the proceeds to fund a distribution to NiSource. If requested by CPG, Columbia OpCo will guarantee such indebtedness. Under the omnibus agreement, at CPG’s request Columbia OpCo will guarantee future indebtedness of CPG. There is no agreement between CPG and Columbia OpCo limiting the amount of CPG indebtedness that Columbia OpCo will be obligated to guarantee. The amount of CPG 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:

 

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make investments and other restricted payments;

 

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incur additional indebtedness or issue preferred stock;

 

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create liens;

 

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

 

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engage in transactions with affiliates.

These covenants or any more restrictive covenants agreed to by CPG in the future could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. A breach by CPG 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 CPG’s bank syndicated credit facility could constitute a default under other CPG debt, which Columbia OpCo may also guarantee. If CPG’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.

CPG 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.

 

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Columbia Pipeline Partners LP

 

Columbia OpCo is a party to a money pool agreement with NiSource Finance, which provides 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 CPG’s credit facility as a source of external funding for all participants. If there were insufficient capacity under the CPG 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 CPG, 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 CPG 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 CPG under its credit agreement and by adverse changes in CPG’s financial condition or results of operations, which will be beyond the control of Columbia OpCo and us. In the event CPG were to default under its credit facility, CPG 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.

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.

Our only asset is a 15.7% 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 is 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 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.

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

 

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

 

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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;

 

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

 

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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:

 

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the level of capital expenditures it makes;

 

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its debt service requirements and other liabilities;

 

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

 

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its ability to borrow funds;

 

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fluctuations in its working capital needs;

 

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the cost of acquisitions, if any; and

 

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the amount of cash reserves established by it.

Our future business opportunities may be limited as a result of our agreement with CPG to refrain from taking any action that would prevent CPG 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 have agreed to refrain from taking any action that would prevent CPG from complying with the tax sharing agreement that CPG may enter into with NiSource in connection with the spin-off. Under such tax sharing agreement, CPG 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 have agreed not to take any action that could cause CPG to violate one of the covenants in the tax sharing agreement. For example, subject to certain limited exceptions, CPG is expected to agree that, for the two years following the spin-off, CPG 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 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-year period following the spin-off, which may adversely impact our financial condition, results of operations and ability to make distributions to you. Please see “Business and Properties—Spin-off of Columbia Pipeline Group.”

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:

 

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

 

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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;

 

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

 

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

 

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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;

 

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an inability to successfully integrate the businesses we build;

 

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

 

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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.

 

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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 accounted for approximately 13% and 9% of our contracted revenues, respectively, for the year ended December 31, 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. Please see Note 18, “Concentration of Credit Risk” in Item 8, Financial Statements and Supplementary Data for further discussion.

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 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 and Utica shale plays. 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.

 

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Columbia Pipeline Partners LP

 

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.

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 approximately 460,000 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;

 

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Columbia Pipeline Partners LP

 

 

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the timing of initiating the drilling and recompleting of wells;

 

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the extent of operating costs;

 

•

selection of technology and drilling and completion methods; and

 

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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 2014 and 2013, 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.

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 PCBs at specific gas transmission facilities pursuant to a 1995 AOC (subsequently modified in 1996 and 2007) 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 December 31, 2014, Columbia Gas Transmission has recorded $1.8 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 CAA that, among other things, restrict emissions of

 

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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.

In one final example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas sector facilities, including natural gas transmission infrastructure and equipment, as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. If proposed and adopted, new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which costs, delays or curtailment could adversely affect our business.

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 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.

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 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:

 

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perform ongoing assessments of pipeline integrity;

 

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

 

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improve data collection, integration and analysis;

 

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repair and remediate the pipeline as necessary; and

 

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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 $211.4 million ($106.9 million in capital costs and $104.5 million in expenses) between 2007 and 2014 associated with the assessment of our pipelines to implement the integrity management program. We currently anticipate that we will continue to incur similarly substantial capital and operating maintenance costs in the future.

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.

 

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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 NGPSA was amended on January 3, 2012 when the president signed the 2011 Pipeline Safety Act. The DOT issued an advanced notice of proposed rulemaking in August of 2011 that addressed approximately 15 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 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.

 

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Columbia Pipeline Partners LP

 

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 NGA. Under the NGA, we may only charge rates that have been 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

 

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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 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.

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:

 

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aging infrastructure, mechanical or other performance problems;

 

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

 

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

 

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

 

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operator error;

 

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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

 

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explosions and blowouts.

 

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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 are a party to a $500 million credit facility, which is guaranteed by NiSource, CPG, CEG, OpCo GP and Columbia OpCo. Following CPG’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 CPG, with $750 million of reserved borrowing capacity, which will be undrawn at the time of closing. In addition, Columbia OpCo, CEG and OpCo GP will guarantee CPG’s credit facility as well as future CPG 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:

 

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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;

 

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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

 

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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 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.

Our 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:

 

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make distributions if any default or event of default occurs;

 

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

 

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incur additional indebtedness or guarantee other indebtedness;

 

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grant liens or make certain negative pledges;

 

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make certain loans or investments;

 

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engage in transactions with affiliates;

 

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

 

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

 

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Furthermore,

We are a party to a $500 million credit facility, which is guaranteed by NiSource, CPG, CEG, OpCo GP and Columbia OpCo. Following CPG’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 CPG, with $750 million of reserved borrowing capacity, which will be undrawn at the time of closing. In addition, Columbia OpCo, CEG and OpCo GP will guarantee CPG’s credit facility as well as future CPG 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:

 

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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;

 

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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

 

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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.

Our 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 make these accelerated payments. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please see “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, CPG, or Columbia OpCo’s guarantee of CPG 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, CPG, or Columbia OpCo’s guarantee of CPG 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, CPG, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.

 

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If we seek a credit rating in the future, our credit rating may be adversely affected by our guarantee of CPG debt and the leverage of our general partner or NiSource, and, following the spin-off, CPG, 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, CPG, 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, CPG, 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.

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:

 

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new projects may fail to be developed;

 

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new projects may not be developed at their announced capacity;

 

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development of new projects may be significantly delayed;

 

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

 

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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.

 

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Columbia Pipeline Partners LP

 

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;

 

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mistaken assumptions about the overall costs of equity or debt;

 

•

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

 

•

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

 

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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 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.

 

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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.

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.

As of February 11, 2015, our sponsor owns a 46.5% limited partner interest in us and controls 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:

 

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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;

 

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

 

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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;

 

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

 

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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. 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;

 

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•

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, CPG may elect to act in a manner that protects CPG’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 CPG 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;

 

•

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;

 

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

 

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

 

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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.

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.

Pursuant to our cash distribution policy 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.

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

 

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Columbia Pipeline Partners LP

 

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.

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.

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:

 

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how to allocate business opportunities among us and its affiliates;

 

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whether to exercise its call right;

 

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

 

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whether to exercise its registration rights;

 

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whether to elect to reset target distribution levels; and

 

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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.

 

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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:

 

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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;

 

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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

 

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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.

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 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.

 

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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 the 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.

Our partnership agreement designates 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 provides 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 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.

 

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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. 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 are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units 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. As of February 11, 2015, our sponsor owned an aggregate of 46.5% of our common and subordinated units. 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.

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

 

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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”). As of February 11, 2015, our sponsor owned an aggregate of 46.5% 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 46.5% of our common units.

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;

 

•

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.

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.

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 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.

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.

Prior to our initial public offering, we were not required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and therefore were not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. As a publicly traded partnership, we are 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 this annual report. 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.

 

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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.

Because we are 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, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Tax Risks 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 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 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.

 

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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, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate 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.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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 positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of 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 are required to pay taxes on your share of our taxable income.

You are 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.

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.

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

 

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that are exempt from federal income tax, including IRAs and other retirement plans, are 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 its 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 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 have adopted 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.

We 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 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. 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 deduction among our unitholders.

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

 

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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. CEG indirectly owns 46.5% 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 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 has 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.

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 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 3. LEGAL PROCEEDINGS

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other partnerships, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Limited Partner Interests

Our common units began trading on the NYSE under the symbol “CPPL” on February 6, 2015, at an initial offering price of $23.00 per common unit. Prior to that time, there was no public market for our common units. Given the initial public offering consummated on February 11, 2015, the number of record holders is indeterminate at this time. As of February 11, 2015, CEG owned all of our subordinated units and incentive distribution rights.

Our common units have been traded on the NYSE since February 6, 2015, and therefore, we have not set forth quarterly information with respect to the high and low prices for our common units. On February 13, 2015, the closing price of our common units was $28.18.

Cash Distribution Policy

General

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 from February 11, 2015, the date of our initial public offering, through March 31, 2015.

Minimum Quarterly Distribution

Our partnership agreement provides that during the subordination period, holders of our common units have the right to receive distributions of available cash from our operating surplus (as defined in our partnership agreement) each quarter in an amount equal to $0.1675 per common unit, defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution to holders of the common units from prior quarters, before any distributions of available cash from operating surplus may be made to holders of the subordinated units. These units are deemed to be subordinated because for the subordination period, holders of the subordinated units are not entitled to receive any distributions from operating surplus until holders of the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. No arrearages are paid on the subordinated units.

General Partner Interest

Our general partner owns a non-economic general partner interest in us that does not entitle it to receive cash distributions. However, our general partner may own common units or other equity securities 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.

 

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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%

Securities Authorized for Issuance under Equity Compensation Plans

See “Part III. Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans.

 

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read in connection with the Combined Financial Statements including the related notes included in Item 8 of this Form 10-K.

For periods prior to the closing of Columbia Pipeline Partners LP’s initial public offering on February 11, 2015, the selected data presented represents the Columbia Pipeline Partners LP Predecessor. The Predecessor is comprised of NiSource’s Columbia Pipeline Group Operations reportable segment. Substantially all of the Columbia Pipeline Group Operations reportable segment was contributed to CPG OpCo LP on February 11, 2015. The Partnership owns a 15.7% limited partner interest in CPG OpCo LP. The selected data covering periods prior to the closing of the initial public offering may not necessarily be indicative of the actual results of operations had the Partnership operated separately during those periods.

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 Measure” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 

		Columbia Pipeline Partners LP
		Predecessor Historical
		Year Ended December 31,
		2014				2013				2012				2011				2010
		(in millions, except operating data)
Statement of Operations Data:
Total Operating Revenues		$	1,346.9			$	1,179.4			$	1,000.4			$	1,005.6			$	949.2
Operating Expenses:
Operation and maintenance			630.7				507.1				374.2				377.9				325.5
Operation and maintenance—affiliated			122.9				118.1				105.6				98.3				75.6
Depreciation and amortization			118.6				106.9				99.3				130.0				130.7
(Gain) loss on sale of assets			(34.5	)			(18.6	)			(0.6	)			0.1				(0.1	)
Property and other taxes			67.1				62.2				59.2				56.6				57.4
Total Operating Expenses		$	904.8			$	775.7			$	637.7			$	662.9			$	589.1
Equity Earnings in Unconsolidated Affiliates			46.6				35.9				32.2				14.6				15.0
Operating Income		$	488.7			$	439.6			$	394.9			$	357.3			$	375.1
Other Income (Deductions)
Interest expense—affiliated			(62.0	)			(37.9	)			(29.5	)			(29.8	)			(25.9	)
Other, net			8.8				17.6				1.5				1.2				1.6
Income taxes			166.4				152.4				136.9				125.6				130.4
Net Income		$	269.1			$	266.9			$	230.0			$	203.1			$	220.4

 

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		Columbia Pipeline Partners LP
		Predecessor Historical
		Year Ended December 31,
		2014				2013				2012				2011				2010
		(in millions, except operating data)
Balance Sheet Data (at period end):
Total assets		$	8,107.5			$	7,261.8			$	6,623.2			$	6,142.6			$	5,934.9
Net property, plant and equipment			4,960.2				4,303.4				3,741.5				3,398.7				3,224.2
Long-term debt-affiliated, excluding amounts due within one year			1,472.8				819.8				754.7				294.7				453.4
Total liabilities			3,936.2				3,361.9				2,883.7				2,430.6				2,244.5
Total partners’ net equity			4,171.3				3,899.9				3,739.5				3,712.0				3,690.4
Statement of Cash Flow Data:
Net cash from (used for):
Operating activities		$	568.1			$	454.0			$	474.9			$	435.3			$	376.0
Investing activities			(864.5	)			(797.4	)			(455.5	)			(307.2	)			(297.3	)
Financing activities			296.6				343.1				(18.8	)			(128.1	)			(78.9	)
Other Data:
Adjusted EBITDA		$	598.5			$	542.7			$	496.9			$	491.5			$	503.7
Maintenance capital expenditures			143.4				132.7				209.6				220.0				149.6
Expansion capital expenditures			700.5				664.8				280.0				81.5				152.4
Operating Data:(1)
Contracted firm capacity (MMDth/d)			13.2				12.9				13.2				13.2				11.9
Throughput (MMDth)			2,006.1				1,997.3				2,200.0				2,393.7				2,154.4
Natural gas storage capacity (MMDth)			287				287				283				282				283

(1)

Excludes equity investments.

Non-GAAP Financial Measure

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 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.

 

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

 

		Columbia Pipeline Partners LP
		Predecessor Historical
		Year Ended December 31,
		2014				2013				2012				2011				2010
		(in millions)
Net Income		$	269.1			$	266.9			$	230.0			$	203.1			$	220.4
Add:
Interest expense—affiliated			62.0				37.9				29.5				29.8				25.9
Income taxes			166.4				152.4				136.9				125.6				130.4
Depreciation and amortization			118.6				106.9				99.3				130.0				130.7
Distributions of earnings received from equity investees			37.8				32.1				34.9				18.8				12.9
Less:
Other, net			8.8				17.6				1.5				1.2				1.6
Equity earnings in unconsolidated affiliates			46.6				35.9				32.2				14.6				15.0
Adjusted EBITDA		$	598.5			$	542.7			$	496.9			$	491.5			$	503.7
		Columbia Pipeline Partners LP
		Predecessor Historical
		Year Ended December 31,
		2014				2013				2012				2011				2010
		(in millions)
Net Cash Flows from Operating Activities		$	568.1			$	454.0			$	474.9			$	435.3			$	376.0
Interest expense—affiliated			62.0				37.9				29.5				29.8				25.9
Current taxes			27.1				(27.5	)			92.2				48.8				40.1
Other adjustments to operating cash flows			28.8				6.1				1.4				(4.1	)			9.8
Changes in assets and liabilities			(87.5	)			72.2				(101.1	)			(18.3	)			51.9
Adjusted EBITDA		$	598.5			$	542.7			$	496.9			$	491.5			$	503.7

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 are conducted through Columbia OpCo, a recently formed partnership between CEG and us. Our assets consist of a 15.7% 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 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 an underground natural gas storage system, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2014, 94% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years.

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities, including approximately $4.9 billion of identified projects that we expect will be completed by the end of the first quarter 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 11,400 miles of natural gas transmission pipeline, 89 compressor stations with 635,671 horsepower of installed capacity and approximately 3,436 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.

 

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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 3,300 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,238 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 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.

 

 

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•

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 and the ability to deliver 176,000 Dth/d. 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 103 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 80 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 approximately 460,000 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 of Columbia Pipeline Group

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 CPG. 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, CPG will continue to indirectly own our general partner, 84.3% 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.

 

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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 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 2,238,637 million cubic feet in October 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 $2.69/MMBtu as of January 30, 2015. 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, 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.

 

 

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•

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, Pennsylvania 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 invested 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 replaced approximately 19 miles of existing 20-inch pipeline with a 24-inch pipeline and added 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 approximately 10-mile 20-inch pipeline and compression facilities will support Marcellus shale production in western Pennsylvania. Approximately 50% of the increased capacity generated by the project is 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 received 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.

 

•

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.

 

•

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.

 

 

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•

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 1.5 MMDth/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 $1.4 billion in this 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. The project also includes the creation of a new compressor station. 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 $383 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 added compression in order to transport 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. 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 Columbia Gas Transmission 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 2014, we completed nearly 40 individual projects bringing the total program investment to approximately $618 million. The modernization program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

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.

 

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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 ceased on January 31, 2015. As of December 31, 2014, Columbia Gas Transmission has recorded $1.8 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.

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.

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.

 

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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.

Revenues and Contract Mix. 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.

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, 2014, approximately 94.1% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 4.0% of the transportation and storage revenues were derived from usage fees under firm contracts compared to 93.1% and 5.0%, respectively, for the year ended December 31, 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

 

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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 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, 2014 and 2013, approximately 1.9% 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.

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.

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

 

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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 see “Selected Financial Data—Non-GAAP Financial Measure.”

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 did 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 was contributed to Columbia OpCo.

 

•

We own a 15.7% interest in Columbia OpCo rather than the 100% ownership reflected as part of the Predecessor’s historical financial results. We control Columbia OpCo through our ownership of its general partner. Our historical financial statements 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 84.3% interest will be reflected as a non-controlling interest.

 

•

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.

 

•

Short-term borrowings – affiliated and a portion of the long-term debt—affiliated (including current portion of long-term debt – affiliated) have been transferred to an affiliate of NiSource and the related interest expense is no longer being incurred.

 

•

We have entered into a $500 million revolving credit facility. We 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 see “Risk Factors.”

Benefits from System Expansions. We expect that our results of operations for the year ending December 31, 2014 and thereafter 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.

 

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Growth Opportunities. We expect the revenues generated from our 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.

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 1.3%, 9.2%, and 8.7% respectively, between 2015 and 2024. 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 13.6%, 5.6% and 8.0%, respectively.

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.

 

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Results of the Predecessor’s Operations

The following schedule presents the Predecessor’s historical combined key operating and financial metrics.

 

		Year Ended December 31,
		2014				2013				2012
		(in millions)
Operating Revenues
Transportation revenues		$	990.9			$	850.9			$	679.4
Transportation revenues—affiliated			95.8				94.3				96.0
Storage revenues			144.0				142.8				144.3
Storage revenues—affiliated			53.2				53.6				52.4
Other revenues			63.0				37.8				28.3
Total Operating Revenues			1,346.9				1,179.4				1,000.4
Operating Expenses
Operation and maintenance			630.7				507.1				374.2
Operation and maintenance—affiliated			122.9				118.1				105.6
Depreciation and amortization			118.6				106.9				99.3
Gain on sale of assets			(34.5	)			(18.6	)			(0.6	)
Property and other taxes			67.1				62.2				59.2
Total Operating Expenses			904.8				775.7				637.7
Equity Earnings in Unconsolidated Affiliates			46.6				35.9				32.2
Operating Income			488.7				439.6				394.9
Other Income (Deductions)
Interest expense—affiliated			(62.0	)			(37.9	)			(29.5	)
Other, net			8.8				17.6				1.5
Total Other Deductions, net			(53.2	)			(20.3	)			(28.0	)
Income before Income Taxes			435.5				419.3				366.9
Income Taxes			166.4				152.4				136.9
Net Income		$	269.1			$	266.9			$	230.0
Throughput (MMDth)
Columbia Gas Transmission			1,379.4				1,354.3				1,305.7
Columbia Gulf			626.7				643.0				894.3
Total			2,006.1				1,997.3				2,200.0

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Operating Revenues. Operating revenues were $1,346.9 million for 2014, an increase of $167.5 million from the same period in 2013. The increase in operating revenues was due primarily to increased revenue of $88.4 million attributable to recovery of operating costs under our regulatory tracker mechanisms, which is offset in expense, increased revenue of $54.7 million primarily from the West Side Expansion, Warren County and Big Pine projects and other new contracts. Additionally there was increased mineral rights royalty revenue of $22.6 million primarily attributable to increased third-party drilling activity.

Operating Expenses. Operating expenses were $904.8 million for 2014, an increase of $129.1 million from the same period in 2013. The increase in operating expenses was primarily due to $88.4 million of increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, increased employee and administrative expenses of $28.3 million due to higher employee costs, increased outside service costs of $13.3 million, higher depreciation and amortization of $11.7 million primarily due to increased capital expenditures related to projects placed in service, and higher property taxes of $4.0 million. These increases were partially offset by higher gains on the sale of assets of $15.9 million resulting from higher gains on the conveyances of mineral interests of $27.2 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 $8.9 million.

 

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Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $46.6 million in 2014, an increase of $10.7 million compared with 2013. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline.

Other Income (Deductions). Other Income (Deductions) in 2014 reduced income by $53.2 million compared to a reduction in income of $20.3 million in 2013. The increase in deductions was primarily due to a $24.1 million increase in interest expense resulting from $768.9 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 $4.2 million increase in the equity portion of allowance for funds used during construction.

Income Taxes. The effective income tax rates were 38.2% and 36.3% in 2014 and 2013, respectively. The change in the overall effective tax rates between 2014 and 2013 were due primarily to AFUDC-Equity and consolidated state income tax benefits.

Throughput. Throughput for the Predecessor totaled 2,006.1 MMDth for 2014, compared to 1,997.3 MMDth for the same period in 2013. This increase is primarily due to colder weather experienced during early 2014 throughout much of our system.

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.

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.

 

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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 our initial public offering, we have established separate bank accounts, but CEG or its affiliates 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. In connection with our initial public offering, CEG assumed 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 novated the $1.2 billion of intercompany debt from the subsidiaries to CEG.

Subsequent to the completion of our initial public offering, our sources of liquidity 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 CPG. In connection with the spin-off, CPG expects to issue a significant amount of new senior indebtedness. Under the omnibus agreement, at CPG’s request Columbia OpCo will guarantee future indebtedness of CPG. 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 see “Risk Factors—Risks Inherent in Our Business—Columbia OpCo will be a restricted subsidiary and a guarantor under CPG’s credit facility and, if requested by CPG, will guarantee future CPG 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.”

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.

 

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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, 2014, 2013 and 2012, were as follows:

 

		For the Years Ended December 31,
		2014				2013				2012
		(in millions)
Net cash from operating activities		$	568.1			$	454.0			$	474.9
Net cash used for investing activities		$	(864.5	)		$	(797.4	)		$	(455.5	)
Net cash from (used for) financing activities		$	296.6			$	343.1			$	(18.8	)

Operating Activities

Net cash from operating activities for the year ended December 31, 2014 was $568.1 million, an increase of $114.1 million from a year ago. The increase in net cash from operating activities was primarily due to an increase in customer deposits related to growth projects of $75.6 million partially offset by a decrease 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, 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.

Investing Activities

The table below reflects actual maintenance and expansion capital expenditures and other investing activities for years ended December 31, 2014, 2013 and 2012 and estimates for 2015.

 

		Year Ended December 31,
		2015E				2014				2013				2012
		(in millions)
Expansion - modernization, system growth, and equity investments		$	912.2			$	700.5			$	664.8			$	280.0
Maintenance			146.5				143.4				132.7				209.6
Total(1)		$	1,058.7			$	843.9			$	797.5			$	489.6

 

(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 2014 were higher than 2013 by approximately $46.4 million due to system growth 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.

The capital expenditure program and other investing activities in 2015 are projected to be approximately $1,058.7 million. The projected 2015 expenditures are comprised of (i) a current profile of identified growth projects and (ii) modernization and maintenance capital expenditures.

 

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Financing Activities

Net cash from financing activities for the year ended December 31, 2014 was $296.6 million, a decrease of $46.5 million from a year ago. The decrease in net cash from financing activities was due to a decrease in short-term borrowings from the money pool to fund capital expenditures. These decreases were partially offset by a decrease in dividends to parent and 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 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, of which $50 million will be available for the issuance of letters of credit. We had no borrowings as of December 31, 2014. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls.

Our obligations under the revolving credit facility are unsecured, however, if the credit rating of CPG 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 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 CPG, 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 CPG, 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 CPG, once NiSource is released as a guarantor from our revolving credit facility.

The revolving indebtedness under the credit facility ranks equally with all our outstanding unsecured and unsubordinated debt. NiSource, CPG, CEG, OpCo GP and Columbia OpCo each fully guarantee the credit facility, except that NiSource will be released from its guarantee upon receipt by CPG of a rating by Moody’s and S&P.

The revolving credit facility was executed on December 5, 2014 but did not become effective until the closing of our initial public offering. Additionally, our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability 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 CPG 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.

 

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Columbia OpCo Money Pool Agreement. In connection with the closing of our initial public offering, Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement initially with NiSource Finance and, following the spin-off, with CPG with $750 million of reserved borrowing capacity, which was undrawn upon as of December 31, 2014. The money pool is available for its general partnership purposes, including capital expenditures and working capital.

In furtherance of the money pool arrangement, CPG 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, CPG expects that its credit facility will be available for its general corporate purposes, including working capital.

We expect that the obligations of CPG under its revolving credit facility will be unsecured, however, if the credit rating of CPG 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 CPG’s revolving credit facility. The loans thereunder shall bear interest at CPG’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 CPG, 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 CPG. CPG’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 CPG.

CPG’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 CPG’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. CPG’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of an amount to be agreed.

CPG’s revolving credit facility also contains certain financial covenants that will require CPG 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 CPG’s revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00 and (b) until CPG has received an investment grade rating, a Consolidated Interest Coverage Ratio (as defined in CPG’s revolving credit facility) of no less than 3.00 to 1.00.

In addition, a breach by CPG 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.

 

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Contractual Obligations. The Predecessor has certain contractual obligations requiring payments at specified periods. The obligations include long-term debt-affiliated (including current portion of long-term debt-affiliated), lease obligations and service obligations for pipeline service agreements. The total contractual obligations in existence at December 31, 2014 and their maturities were:

 

		Total				2015				2016				2017				2018				2019				After
		(in millions)
Long-term debt-affiliated(1)		$	1,588.7			$	115.9			$	879.3			$	—			$	—			$	—			$	593.5
Interest payments on long-term debt(1)			781.4				79.5				73.5				31.7				31.7				31.7				533.3
Pipeline transportation capacity agreements			224.7				42.7				42.0				38.6				25.9				19.2				56.3
Operating leases(2)			49.6				4.7				3.4				5.8				5.5				5.3				24.9
Total contractual obligations		$	2,644.4			$	242.8			$	998.2			$	76.1			$	63.1			$	56.2			$	1,208.0

⁽¹⁾ Includes current portion of long-term debt – affiliated.

⁽²⁾ Operating lease expense was $14.9 million in 2014, $13.4 million in 2013 and $10.7 million in 2012, 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 2015 to 2025, 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.

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 $158.0 million and $295.6 million at December 31, 2014, and $142.6 million and $283.1 million at December 31, 2013, respectively. For further discussion, please see Note 8, “Regulatory Matters,” in the Predecessor’s audited Notes to Combined Financial Statements.

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, 2014. Regulatory assets of $23.9 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.

 

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Pensions and Postretirement Benefits. NiSource has defined benefit plans for both pensions and other postretirement benefits that cover our employees. 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, please see Note 11, “Pension and Other Postretirement Benefits,” in the Predecessor’s audited Notes to Combined Financial Statements.

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 December 31, 2014 and 2013 were $1,975.5 million 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.

Please see Notes 1-I and 6, “Goodwill” in the Predecessor’s audited Notes to Combined Financial Statements for further discussion.

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.

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.

Our subsidiary CEVCO owns the mineral rights to approximately 460,000 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 $43.8 million, $21.2 million and $18.5 million for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in “Other revenues” on the Combined Statement of Operations.

 

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We periodically recognize gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if 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. Gains on the conveyance of mineral interest were $34.5 million, $7.3 million, and zero for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in “Gain on sale of assets” 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.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE 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 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 December 31, 2014, the outstanding balance on this term loan was $834.0 million. An increase or decrease of 100 basis points in interest rate would result in $8.3 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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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index			Page
Columbia Pipeline Partners LP
Audited Balance Sheets
Report of Independent Registered Public Accounting Firm			71
Balance Sheets as of December 31, 2014 and June 30, 2014			72
Notes to the Balance Sheets			73
Columbia Pipeline Partners LP Predecessor
Audited Historical Financial Statements
Report of Independent Registered Public Accounting Firm			74
Combined Balance Sheets as of December 31, 2014 and 2013			75
Combined Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012			76
Combined Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012			77
Combined Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			78
Combined Statements of Parent Net Equity for the Years Ended December 31, 2014, 2013 and 2012			79
Notes to Combined Financial Statements			80

 

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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 balance sheets of Columbia Pipeline Partners LP (the “Company”) at December 31, 2014 and June 30, 2014. 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 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 balance sheets present fairly, in all material respects, the financial position of Columbia Pipeline Partners LP at December 31, 2014 and June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the balance sheets, on February 11, 2015 Columbia Pipeline Partners LP completed its initial public offering of limited partner interests for net proceeds of $1,170.0 million.

/s/ Deloitte & Touche LLP

Chicago, Illinois

February 18, 2015

 

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Columbia Pipeline Partners LP

Balance Sheets

 

		As of December 31, 2014				As of June 30, 2014
		(in dollars)
ASSETS
Total Assets		$	—			$	—
PARTNERS’ EQUITY
Partners’ Equity
Limited partners’ equity		$	1,960			$	1,960
General partners’ equity			40				40
Less note receivable from NiSource Inc.			(2,000	)			(2,000	)
Total Liabilities and Partners’ Equity		$	—			$	—

The accompanying Notes to the Balance Sheets are an integral part of this statement.

 

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Columbia Pipeline Partners LP Notes to the Balance Sheets

 

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 15.7% 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.

 

2.	Subsequent Event

Closing of Initial Public Offering. On February 11, 2015, the Partnership completed its initial public offering of 53,833,107 common units representing limited partnership interests, constituting approximately 53.5% of the Partnership’s outstanding limited partnership interests. The Partnership received approximately $1,170.0 million of net proceeds from the initial public offering. CEG owns the general partner of the Partnership, all of the Partnership’s subordinated units and the incentive distribution rights. The assets of the Partnership consist of a 15.7% limited partner interest in Columbia OpCo, which consists of substantially all of the Columbia Pipeline Group Operations segment.

In conjunction with the closing of the initial public offering, the Partnership entered into a $500.0 million revolving credit facility, of which $50 million will be available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures and the funding of capital calls. The facility is guaranteed by NiSource, CPG, CEG, OpCo GP and Columbia OpCo.

 

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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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 20 to the combined financial statements, on February 11, 2015 Columbia Pipeline Partners LP completed its initial public offering of limited partner interests for net proceeds of $1,170.0 million.

/s/ Deloitte & Touche LLP

Chicago, Illinois

February 18, 2015

 

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Columbia Pipeline Partners LP Predecessor

Combined Balance Sheets

 

		As of December 31,
		2014				2013
		(in millions)
ASSETS
Current Assets
Cash and cash equivalents		$	0.5			$	0.3
Accounts receivable (less reserve of $0.3 and $0.1, respectively)			149.3				128.0
Accounts receivable—affiliated			153.8				94.4
Materials and supplies, at average cost			24.9				24.8
Exchange gas receivable			34.8				49.2
Regulatory assets			6.1				12.3
Deferred property taxes			48.9				46.8
Deferred income taxes			24.6				9.7
Prepayments and other			14.8				12.6
Total Current Assets			457.7				378.1
Investments
Unconsolidated affiliates			444.3				364.5
Other investments			6.2				12.3
Total Investments			450.5				376.8
Property, Plant and Equipment
Property, plant and equipment			7,931.6				7,191.4
Accumulated depreciation and amortization			(2,971.4	)			(2,888.0	)
Net Property, Plant and Equipment			4,960.2				4,303.4
Other Noncurrent Assets
Regulatory assets			151.9				130.3
Goodwill			1,975.5				1,975.5
Postretirement and postemployment benefits assets			102.7				93.1
Deferred charges and other			9.0				4.6
Total Other Noncurrent Assets			2,239.1				2,203.5
Total Assets		$	8,107.5			$	7,261.8
LIABILITIES AND PARENT NET EQUITY
Current Liabilities
Current portion of long-term debt—affiliated		$	115.9			$	-
Short-term borrowings—affiliated			247.3				719.6
Accounts payable			56.1				71.9
Accounts payable—affiliated			49.9				41.3
Customer deposits			13.4				11.5
Taxes accrued			106.9				96.0
Exchange gas payable			34.7				48.1
Deferred revenue			22.2				14.9
Regulatory liabilities			1.3				0.8
Legal and environmental			1.5				8.4
Accrued capital expenditures			61.1				26.7
Other accruals			67.4				58.1
Total Current Liabilities			777.7				1,097.3
Noncurrent Liabilities
Long-term debt—affiliated			1,472.8				819.8
Deferred income taxes			1,239.0				1,077.0
Deferred revenue			—				17.1
Accrued liability for postretirement and postemployment benefits			44.7				32.7
Regulatory liabilities			294.3				282.3
Asset retirement obligations			23.2				26.3
Other noncurrent liabilities			84.5				9.4
Total Noncurrent Liabilities			3,158.5				2,264.6
Total Liabilities			3,936.2				3,361.9
Commitments and Contingencies (Refer to Note 13)
Parent Net Equity
Net parent investment			4,188.0				3,917.6
Accumulated other comprehensive loss			(16.7	)			(17.7	)
Total Parent Net Equity			4,171.3				3,899.9
Total Liabilities and Parent Net Equity		$	8,107.5			$	7,261.8

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,
		2014				2013				2012
		(in millions)
Operating Revenues
Transportation revenues		$	990.9			$	850.9			$	679.4
Transportation revenues—affiliated			95.8				94.3				96.0
Storage revenues			144.0				142.8				144.3
Storage revenues—affiliated			53.2				53.6				52.4
Other revenues			63.0				37.8				28.3
Total Operating Revenues			1,346.9				1,179.4				1,000.4
Operating Expenses
Operation and maintenance			630.7				507.1				374.2
Operation and maintenance—affiliated			122.9				118.1				105.6
Depreciation and amortization			118.6				106.9				99.3
Gain on sale of assets			(34.5	)			(18.6	)			(0.6	)
Property and other taxes			67.1				62.2				59.2
Total Operating Expenses			904.8				775.7				637.7
Equity Earnings in Unconsolidated Affiliates			46.6				35.9				32.2
Operating Income			488.7				439.6				394.9
Other Income (Deductions)
Interest expense—affiliated			(62.0	)			(37.9	)			(29.5	)
Other, net			8.8				17.6				1.5
Total Other Deductions, net			(53.2	)			(20.3	)			(28.0	)
Income before Income Taxes			435.5				419.3				366.9
Income Taxes			166.4				152.4				136.9
Net Income		$	269.1			$	266.9			$	230.0

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,
		2014				2013				2012
		(in millions, net of taxes)
Net Income		$	269.1			$	266.9			$	230.0
Other comprehensive income (loss):
Net unrealized gain on cash flow hedges(1)			1.0				1.1				1.0
Unrecognized pension and OPEB costs(2)			—				—				(0.1	)
Total other comprehensive income			1.0				1.1				0.9
Total Comprehensive Income		$	270.1			$	268.0			$	230.9

 

(1)	Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.7 million, $0.6 million and $0.6 million tax expense in 2014, 2013 and 2012, respectively.

 

(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,
		2014				2013				2012
		(in millions)
Operating Activities
Net Income		$	269.1			$	266.9			$	230.0
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations
Depreciation and amortization			118.6				106.9				99.3
Deferred income taxes and investment tax credits			139.3				179.9				44.7
Deferred revenue			1.6				(0.5	)			(4.1	)
Stock compensation expense and 401(k) profit sharing contribution			6.3				2.2				3.2
Gain on sale of assets			(34.5	)			(18.6	)			(0.6	)
Income from unconsolidated affiliates			(46.6	)			(35.9	)			(32.2	)
AFUDC equity			(11.0	)			(6.8	)			(1.4	)
Distributions of earnings received from equity investees			37.8				32.1				34.9
Changes in Assets and Liabilities
Accounts receivable—affiliated			2.2				(7.6	)			14.8
Accounts receivable			(20.3	)			2.5				(14.2	)
Accounts payable—affiliated			8.6				16.3				(6.0	)
Accounts payable			2.8				5.5				16.7
Customer deposits			77.5				1.3				1.3
Taxes accrued			11.8				(28.5	)			33.8
Exchange gas receivable/payable			1.1				(0.5	)			1.4
Other accruals			0.6				0.4				0.8
Prepayments and other current assets			(4.4	)			21.7				(24.9	)
Regulatory assets/liabilities			9.0				42.6				56.5
Postretirement and postemployment benefits			2.2				(113.3	)			17.0
Deferred charges and other noncurrent assets			(4.3	)			2.5				13.4
Other noncurrent liabilities			0.7				(15.1	)			(9.5	)
Net Cash Flows from Operating Activities			568.1				454.0				474.9
Investing Activities
Capital expenditures			(747.2	)			(674.8	)			(431.7	)
Insurance recoveries			11.3				6.4				6.5
Changes in short-term lendings—affiliated			(61.6	)			(10.0	)			(24.4	)
Proceeds from disposition of assets			9.3				15.4				22.7
Contributions to equity investees			(69.2	)			(125.5	)			(20.4	)
Other investing activities			(7.1	)			(8.9	)			(8.2	)
Net Cash Flows used for Investing Activities			(864.5	)			(797.4	)			(455.5	)
Financing Activities
Changes in short-term borrowings—affiliated			(472.3	)			391.0				(111.1	)
Issuance of long-term debt—affiliated			768.9				65.1				460.0
Repayments of long-term debt—affiliated			—				—				(158.7	)
Dividends to parent			—				(113.0	)			(209.0	)
Net Cash Flows from (used for) Financing Activities			296.6				343.1				(18.8	)
Change in cash and cash equivalents			0.2				(0.3	)			0.6
Cash and cash equivalents at beginning of period			0.3				0.6				—
Cash and Cash Equivalents at End of Period		$	0.5			$	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, 2012		$	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
Net Income			269.1				—				269.1
Other comprehensive income, net of tax			—				1.0				1.0
Net transfers from parent			1.3				—				1.3
Balance December 31, 2014		$	4,188.0			$	(16.7	)		$	4,171.3

 

(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 Formed in Delaware on December 5, 2007, the Partnership is a subsidiary of 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 initial public offering completed on February 11, 2015, NiSource contributed substantially all of the assets and operations of Columbia Pipeline Partners LP Predecessor (the “Predecessor”) to Columbia OpCo, a Delaware limited partnership formed by CEG, a wholly owned subsidiary of NiSource and CPG OpCo GP LLC (“OpCo GP”), a wholly owned subsidiary of the Partnership. The Partnership owns a 15.7% limited partner interest in Columbia OpCo and CEG owns the remaining 84.3% limited partner interest. CPP GP LLC (“MLP GP”), a wholly owned subsidiary of CEG, serves as the general partner for the Partnership. OpCo GP serves as the general partner for Columbia OpCo. Columbia Pipeline Group Services Company provides services to the Partnership pursuant to an omnibus agreement. MLP GP, the Partnership, Columbia OpCo and OpCo GP have all adopted a fiscal year end of December 31.

The Predecessor is engaged in regulated interstate 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 tariffs 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 in 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 through a distribution to NiSource stockholders of all of the outstanding common stock of CPG. The spin-off is expected to take place in the second half of 2015, subject to satisfaction of various conditions.

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.

 

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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. Please see Note 8, “Regulatory Matters,” in the Notes to Combined Financial Statements for further discussion.

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. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and AFUDC equity are summarized in the table below:

 

		2014								2013								2012
		Debt				Equity				Debt				Equity				Debt				Equity
Columbia Gas Transmission			0.9%				3.0%				2.5%				3.2%				2.1%				1.7%
Columbia Gulf			2.1%				9.4%				2.5%				3.2%				2.1%				1.7%

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 2014, 2013 or 2012. Please see Note 4, “Gain on Sale of Assets,” in the Notes to Combined Financial 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.

 

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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 $4.3 million in 2014, $5.0 million in 2013 and $3.8 million in 2012 related to software costs. The Predecessor’s unamortized software balance was $18.3 million and $12.7 million at December 31, 2014 and 2013, respectively.

I. Goodwill. The Predecessor has $1,975.5 million 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. Please see Note 6, “Goodwill,” in the Notes to Combined Financial Statements for further discussion.

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.

The Predecessor includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 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 $43.8 million, $21.2 million and $18.5 million for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in “Other revenues” on the Combined Statement of Operations.

The Predecessor periodically recognizes gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if 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. Gains on the conveyance of mineral interest were $34.5 million, $7.3 million, and zero for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in “Gain on sale of assets” 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 2014, 2013 and 2012 tax years that were recorded in equity, were $1.3 million, $5.4 million and $0.2 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. Please see Note 13, “Other Commitments and Contingencies,” in the Notes to Combined Financial Statements for further discussion.

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.

The Predecessor has a 50% interest in Hardy Storage for the periods presented. 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, a 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. Natural Gas and Oil Properties. The Predecessor includes the subsidiary CEVCO which owns the mineral rights approximately 460,000 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. Please see Note 1K, “Revenue Recognition,” in the Notes to Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO participates as a working interest partner in the development 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. 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 field-by-field basis considering a combination of time, geologic and engineering factors.

The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2014 and 2013:

 

		2014				2013
		(in millions)
Beginning Balance		$	1.9			$	3.0
Additions pending the determination of proved reserves			20.1				6.0
Reclassifications of proved properties			(7.1	)			(7.1	)
Ending Balance		$	14.9			$	1.9

As of December 31, 2014, there was $0.5 million of capitalized exploratory well costs that have been capitalized for more than one year relating to two projects initiated 2013.

 

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.

 

 

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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,
		2014				2013				2012
		(in millions)
Transportation revenues		$	95.8			$	94.3			$	96.0
Storage revenues			53.2				53.6				52.4
Other revenues			0.3				0.3				0.3
Operation and maintenance expense			122.9				118.1				105.6
Interest expense			62.0				37.9				29.5
Interest income			0.5				0.5				0.5

Balance Sheet. 

 

		At December 31,
		2014				2013
		(in millions)
Accounts receivable		$	153.8			$	94.4
Current portion of long-term debt			115.9				—
Short-term borrowings			247.3				719.6
Accounts payable			49.9				41.3
Long-term debt			1,472.8				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 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 $61.6 million in 2014, $40.6 million in 2013 and $26.1 million in 2012, offset by associated AFUDC of $2.7 million in 2014, $6.8 million in 2013 and $2.3 million in 2012. Please see Note 1F “Property, Plant and Equipment and Related AFUDC and Maintenance” in the Notes to Combined Financial Statements for further discussion 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, 2014 and 2013 was 0.70% and 0.87%, respectively. The interest expense for short-term borrowings charged in 2014, 2013 and 2012 was $3.1 million, $4.1 million and $5.7 million, respectively.

 

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Accounts Receivable. The Predecessor includes in accounts receivable amounts due from the money pool discussed above at December 31, 2014 and 2013 of $125.0 million and $63.4 million for subsidiaries in a net deposit position. Also included in the balance at December 31, 2014 and 2013 are amounts due from subsidiaries of NiSource for transportation and storage services of $28.8 million and $31.0 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, 2014 and 2013 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.

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,
								2014				2013
Origination Date		Interest Rate				Maturity Date		(in millions)
November 28, 2005(1)			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(2)			4.75	%		December 31, 2016			834.0				65.1
Total long-term debt, including current portion								$	1,588.7			$	819.8

 

(1)

The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in “Current portion of long-term debt—affiliated” on the Combined Balance Sheets as of December 31, 2014.

(2)

The Predecessor may borrow at any time from the origination date to the maturity date not to exceed $2.6 billion. The note carries a variable interest rate of prime plus 150 basis points. All funds borrowed on the note are due December 31, 2016.

Dividends. The Predecessor paid no dividends to the parent in 2014 and paid $113.0 million and $209.0 million in dividends to the parent in 2013 and 2012, respectively. There are no restrictions on the payment of dividends.

 

4.	Gain on Sale of Assets

The Predecessor recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. Gains on conveyances of $34.5 million and $7.3 million were recorded in earnings in 2014 and 2013, respectively. As of December 31, 2014 and 2013, deferred gains of approximately $19.6 million and $30.0 million, respectively, were deferred pending performance of future obligations and recorded in deferred revenue on the Combined Balance Sheets.

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.

 

 

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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,
		2014				2013
		(in millions)
Property, plant and equipment
Pipeline and other transmission assets		$	5,328.2			$	4,891.8
Storage facilities			1,326.5				1,253.4
Gas stored base gas			299.5				299.5
Gathering and processing facilities			263.3				260.5
Construction work in process			454.2				238.2
General plant, software, and other assets			259.9				248.0
Property, plant and equipment			7,931.6				7,191.4
Accumulated depreciation and amortization			(2,971.4	)			(2,888.0	)
Net property, plant and equipment		$	4,960.2			$	4,303.4

The table below lists the Predecessor’s applicable annual depreciation rates:

 

Year Ended December 31,

2014

2013

2012

Depreciation rates

Pipeline and other transmission assets

1.00% – 2.55%

1.50% – 2.55%

1.00% – 2.55%

Storage facilities

2.19% – 3.30%

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

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 operating segment management. 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, 2014 and 2013 were $1,975.5 million 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.

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

 

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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.

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 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 the current year 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 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 a subsequent goodwill impairment testing subsequent to May 1, 2014.

 

7.	Asset Retirement Obligations

Changes in the Predecessor’s liability for asset retirement obligations for the years 2014 and 2013 are presented in the table below:

 

		2014				2013
		(in millions)
Beginning Balance		$	26.3			$	19.2
Accretion expense			1.5				1.2
Additions			2.2				6.3
Settlements			(6.6	)			(1.2	)
Change in estimated cash flow			(0.2	)			0.8
Ending Balance		$	23.2			$	26.3

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.

 

88

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Columbia Pipeline Partners LP

 

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.

 

8.	Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets and liabilities of the Predecessor were comprised of the following items:

 

		At December 31,
		2014				2013
		(in millions)
Assets
Unrecognized pension benefit and other postretirement benefit costs		$	120.9			$	101.9
Other postretirement costs			10.8				13.8
Deferred taxes on AFUDC equity			21.8				15.6
Other			4.5				11.3
Total Regulatory Assets		$	158.0			$	142.6
		At December 31,
		2014				2013
		(in millions)
Liabilities
Cost of removal		$	156.2			$	162.6
Regulatory effects of accounting for income taxes			10.9				11.4
Unrecognized pension benefit and other postretirement benefit costs			8.3				20.0
Other postretirement costs			117.3				88.3
Other			2.9				0.8
Total Regulatory Liabilities		$	295.6			$	283.1

No regulatory assets are earning a return on investment at December 31, 2014. Regulatory assets of $23.9 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.

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.

 

89

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Columbia Pipeline Partners LP

 

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.

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, which began 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 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 January 29, 2015, Columbia Gas Transmission received FERC approval of its December 2014 filing to recover costs associated with the second year of its comprehensive system modernization program. Total program adjusted spend to date is $618.1 million. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

 

90

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Columbia Pipeline Partners LP

 

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 Affiliates on the Predecessor’s Combined Statements of Operations. 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, 2014:

 

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	%

 

 

91

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Columbia Pipeline Partners LP

 

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 Combined Statements of Operations.

 

		Year Ended December 31,
		2014				2013				2012
		(in millions)
Millennium Pipeline
Statement of Income Data:
Net Revenues		$	190.5			$	157.8			$	152.3
Operating Income			128.8				101.3				97.7
Net Income			89.6				63.0				57.1
Balance Sheet Data:
Current Assets			32.1				38.3				33.7
Noncurrent Assets			1,016.3				1,033.8				1,013.4
Current Liabilities			42.6				58.8				42.7
Noncurrent Liabilities			568.3				599.7				631.4
Total Members’ Equity			437.5				413.6				373.0
Hardy Storage
Statement of Income Data:
Net Revenues		$	23.6			$	24.4			$	24.4
Operating Income			16.1				16.5				16.4
Net Income			10.6				10.6				10.0
Balance Sheet Data:
Current Assets			12.0				12.5				9.7
Noncurrent Assets			157.4				160.2				164.1
Current Liabilities			17.1				18.3				15.6
Noncurrent Liabilities			77.4				85.7				93.8
Total Members’ Equity			74.9				68.7				64.4
Pennant
Statement of Income Data:
Net Revenues		$	8.5			$	2.0			$	—
Operating (Loss)/Income			(2.4	)			1.3				—
Net (Loss)/Income			(2.4	)			1.3				—
Balance Sheet Data:
Current Assets			23.7				34.1				16.4
Noncurrent Assets			380.0				231.9				31.0
Current Liabilities			8.6				11.4				2.0
Total Members’ Equity			395.1				254.6				45.4

Contributions made to Millennium Pipeline to fund its construction activities were $2.6 million, $16.6 million and $17.5 million for 2014, 2013 and 2012, respectively. Millennium Pipeline distributed $35.6 million, $29.0 million and $31.4 million of earnings to Columbia Gas Transmission during 2014, 2013 and 2012, respectively.

No contributions were made to Hardy Storage during 2014, 2013 or 2012. Hardy Storage distributed $2.2 million, $3.1 million and $3.5 million of available accumulated earnings to NiSource during 2014, 2013 and 2012, respectively.

Pennant was formed by Columbia Midstream and Hilcorp in 2012. Contributions made to Pennant were $66.6 million, $108.9 million, and $2.9 million for 2014, 2013 and 2012, respectively. No distributions have been received from Pennant.

 

 

92

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Columbia Pipeline Partners LP

 

10.	Income Taxes

The components of income tax expense were as follows:

 

		Year Ended December 31,
		2014				2013				2012
		(in millions)
Income Taxes
Current
Federal		$	21.3			$	(16.1	)		$	80.7
State			5.8				(11.4	)			11.5
Total Current			27.1				(27.5	)			92.2
Deferred
Federal			117.7				155.9				41.9
State			21.7				24.1				2.9
Total Deferred			139.4				180.0				44.8
Deferred Investment Credits			(0.1	)			(0.1	)			(0.1	)
Total Income Taxes		$	166.4			$	152.4			$	136.9

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,
		2014								2013								2012
		(in millions)
Book income from Continuing Operations before income taxes		$	435.5							$	419.3							$	366.9
Tax expenses at statutory federal income tax rate			152.4				35.0	%			146.8				35.0	%			128.4				35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit			17.9				4.1				8.2				1.9				9.4				2.5
Amortization of deferred investment tax credits			(0.1	)			—				(0.1	)			—				(0.1	)			—
Nondeductible expenses			1.0				0.2				0.9				0.2				0.9				0.2
AFUDC-Equity			(3.8	)			(0.9	)			(2.4	)			(0.6	)			(0.4	)			(0.1	)
Other, net			(1.0	)			(0.2	)			(1.0	)			(0.2	)			(1.3	)			(0.3	)
Total Income Taxes		$	166.4				38.2	%		$	152.4				36.3	%		$	136.9				37.3	%

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 Internal Revenue Code section 41 until December 31, 2013, and also extended and modified 50% bonus depreciation for 2013. The Predecessor recorded the effects of ATRA in the first quarter 2013. On December 19, 2014, the President signed into law the Tax Increase Prevention Act (“TIPA”). TIPA extended and modified 50% bonus depreciation for 2014. The Predecessor recorded the effects of TIPA in the fourth quarter 2014. In general, 50% bonus depreciation is available for property placed in service before January 1, 2015, or in the case of certain property having longer production periods, before January 1, 2016. The retroactive extension of the research credit did not have a significant effect on net income.

 

93

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Columbia Pipeline Partners LP

 

Tangible Property Regulations and Repairs

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 did not early adopt the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013 which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Predecessor will likely adopt this Revenue Procedure for income tax filings for 2014. The final regulations did not materially affect the financial statements.

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,
		2014				2013
		(in millions)
Deferred tax liabilities
Accelerated depreciation and other property differences		$	1,235.3			$	1,088.0
Pension and other postretirement/postemployment benefits			24.3				20.2
Other regulatory assets			62.8				58.2
Other, net			77.9				56.8
Total Deferred Tax Liabilities			1,400.3				1,223.2
Deferred tax assets
Deferred investment tax credits and other regulatory liabilities			(116.7	)			(107.9	)
Net operating loss carryforward and AMT credit carryforward			(67.8	)			(40.2	)
Other accrued liabilities			(1.4	)			(7.8	)
Total Deferred Tax Assets			(185.9	)			(155.9	)
Net Deferred Tax Liabilities less Deferred Tax Assets			1,214.4				1,067.3
Less: Deferred income taxes related to current assets and liabilities			(24.6	)			(9.7	)
Non-Current Deferred Tax Liabilities		$	1,239.0			$	1,077.0

 

94

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Columbia Pipeline Partners LP

 

The net operating loss carryforward includes a federal carryforward of $67.4 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		2014				2013				2012
		(in millions)
Unrecognized Tax Benefits—Opening Balance		$	0.1			$	4.9			$	15.3
Gross decreases—tax positions in prior period			(0.1	)			(4.8	)			(10.4	)
Gross increases—current period tax positions			—				—				—
Unrecognized Tax Benefits—Ending Balance		$	—			$	0.1			$	4.9
Offset for outstanding IRS refunds			—				—				(4.8	)
Offset for net operating loss carryforwards			—				—				—
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 under the provisions of ASC 740.

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.

The total amount of unrecognized tax benefits at December 31, 2014, 2013 and 2012 that, if recognized, would affect the effective tax rate is zero for December 31, 2014 and $0.1 million for December 31, 2013 and 2012. 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, 2014, 2013 and 2012. For the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012 and there were no balances for accrued penalties recorded on the Combined Balance Sheets as of December 31, 2014 and 2013.

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, 2014, 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. NiSource is involved in the Compliance Assurance Program for tax years 2013 and 2014.

 

95

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Columbia Pipeline Partners LP

 

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, 2014, 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 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.

 

96

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Columbia Pipeline Partners LP

 

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, 2014 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%

Pension Plan and Postretirement Plan Asset Mix allocated to the Predecessor at December 31, 2014 and December 31, 2013:

 

December 31, 2014		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		$	125.2				41.1	%		$	99.9				47.2	%
International Equities			55.0				18.1	%			38.9				18.4	%
Fixed Income			105.0				34.4	%			72.2				34.1	%
Real Estate/Private Equity/Hedge Funds			15.4				5.0	%			—				0.0	%
Cash/Other			4.2				1.4	%			0.6				0.3	%
		$	304.8				100.0	%		$	211.6				100.0	%
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	%

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, 2014 and 2013. 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 $15.3 million and $16.4 million as of December 31, 2014 and 2013, respectively. Such amounts were approximately 3% 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, 2014 and 2013.

 

97

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Columbia Pipeline Partners LP

 

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.

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, 2014, there were no significant changes to valuation techniques to determine the fair value of NiSource’s pension and other postretirement benefits’ assets.

 

98

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Columbia Pipeline Partners LP

 

The following table reflects the Predecessor’s allocation of pension and other postretirement benefit amounts:

 

Fair Value Measurements		December 31, 2014				Quoted Prices in Assets (Level 1)				Significant Inputs (Level 2)				Significant Inputs (Level 3)
		(in millions)
Pension plan assets:
Cash		$	2.2			$	2.2			$	—			$	—
Equity securities
International equities			17.6				17.5				0.1				—
Fixed income securities
Government			15.5				13.7				1.8				—
Corporate			33.6				—				33.6				—
Mortgage/Asset backed securities			0.4				—				0.4				—
Other fixed income			0.1				—				—				0.1
Commingled funds
Short-term money markets			4.3				—				4.3				—
U.S. equities			125.2				—				125.2				—
International equities			36.6				—				36.6				—
Fixed income			53.5				—				53.5				—
Private equity limited partnerships
U.S. multi-strategy(1)			7.3				—				—				7.3
International multi-strategy(2)			4.6				—				—				4.6
Distressed opportunities			1.0				—				—				1.0
Real estate			2.3				—				—				2.3
Pension plan assets subtotal			304.2				33.4				255.5				15.3
Other postretirement benefit plan assets
Commingled funds
Short-term money markets			0.7				—				0.7				—
U.S. equities			13.6				—				13.6				—
Mutual funds
U.S. equities			86.4				86.4				—				—
International equities			38.9				38.9				—				—
Fixed income			72.0				72.0				—				—
Other postretirement benefit plan assets subtotal			211.6				197.3				14.3				—
Due to brokers, net(3)			(0.1	)
Accrued investment income/dividends			0.1
Net receivables			0.6
Total pension and other postretirement benefit plan assets		$	516.4			$	230.7			$	269.8			$	15.3

(1)	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.

(2)	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.

(3)	This class represents pending trades with brokers.

 

99

---

Columbia Pipeline Partners LP

 

The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2013:

 

		Balance at January 1, 2014				Total gains or losses (unrealized/ realized)				Purchases				(Sales)				Transfers into/(out of) Level 3				Balance at December 31, 2014
Fixed income securities
U.S. multi-strategy		$	—			$	—			$	0.1			$	—			$	—			$	0.1
Private equity limited partnerships
U.S. multi-strategy			7.6				0.3				0.3				(0.9	)			—				7.3
International multi-strategy			5.0				(0.1	)			0.1				(0.4	)			—				4.6
Distressed opportunities			1.2				—				—				(0.2	)			—				1.0
Real estate			2.6				0.3				—				(0.6	)			—				2.3
Total		$	16.4			$	0.5			$	0.5			$	(2.1	)		$	—			$	15.3

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(1)			7.6				—				—				7.6
International multi-strategy(2)			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(3)			(1.3	)
Accrued investment income/dividends			0.5
Net receivables(4)			6.3
Total pension and other postretirement benefit plan assets		$	497.9			$	254.0			$	222.0			$	16.4

(1)	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.

 

100

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Columbia Pipeline Partners LP

 

(2)	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.

(3)	This class represents pending trades with brokers.

(4)	Reflects $6.3 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

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, 2014, NiSource had purchases, sales and transfers into (out of) Level 3 assets of $3.5 million, $(16.6) million, and zero, respectively. The net realized and unrealized gain on Level 3 assets was $5.4 million. The Predecessor’s allocation of the activity in 2014 was 13.1%.

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%.

 

101

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Columbia Pipeline Partners LP

 

NiSource 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
		2014				2013				2014				2013
		(in millions)
Change in projected benefit obligation(1)
Benefit obligation at beginning of year		$	327.1			$	372.5			$	105.5			$	128.8
Service cost			4.8				4.8				1.1				1.5
Interest cost			13.7				12.6				4.6				4.9
Plan participants’ contributions			—				—				1.9				1.8
Plan amendments			—				—				—				0.1
Settlement gain			—				2.6				—				—
Actuarial loss (gain)			20.0				(22.8	)			4.6				(22.2	)
Benefits paid			(20.4	)			(42.6	)			(9.1	)			(9.6	)
Estimated benefits paid by incurred subsidiary			—				—				0.3				0.2
Projected benefit obligation at end of year		$	345.2			$	327.1			$	108.9			$	105.5
Change in plan assets
Fair value of plan assets at beginning of year		$	299.1			$	289.9			$	198.8			$	166.0
Actual return on plan assets			19.3				39.9				9.2				30.0
Employer contributions			6.7				11.9				10.8				10.6
Plan participants’ contributions			—				—				1.9				1.8
Benefits paid			(20.4	)			(42.6	)			(9.1	)			(9.6	)
Fair value of plan assets at end of year		$	304.7			$	299.1			$	211.6			$	198.8
Funded status at end of year		$	(40.5	)		$	(28.0	)		$	102.7			$	93.3
Amounts recognized in the balance sheet consist of:
Noncurrent assets		$	—			$	—			$	109.8			$	100.9
Current liabilities			—				—				—				—
Noncurrent liabilities			(40.5	)			(28.0	)			(7.1	)			(7.6	)
Net amount recognized at end of year(2)		$	(40.5	)			(28.0	)		$	102.7			$	93.3
Amounts recognized as regulatory assets/liabilities(3)
Unrecognized prior service (credit) cost		$	(4.0	)		$	(5.0	)		$	0.1			$	0.2
Unrecognized actuarial (gain) loss			124.5				106.9				(8.3	)			(20.2	)
Total recognized regulatory assets (liabilities)		$	120.5			$	101.9			$	(8.2	)		$	(20.0	)

 

(1)	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.

(2)	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.

(3)

The Predecessor determined that the future recovery of pension and other postretirement benefits costs is probable. The Predecessor recorded regulatory assets and liabilities of $120.9 million and $8.3 million, respectively, as of December 31, 2014 and $101.9 million and $20.0 million, respectively, as of December 31, 2013, that would otherwise have been recorded to accumulated other comprehensive loss.

The Predecessor’s accumulated benefit obligation for its pension plans was $345.2 million and $327.1 million as of December 31, 2014 and 2013, 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 Predecessor’s pension plans were underfunded by $40.5 million at December 31, 2014 compared to being underfunded by $28.0 million at December 31, 2013. The decline in the funded status was due primarily to a decrease in the discount rate from the prior measurement date and the implementation of new mortality assumptions released by the Society of Actuaries in 2014, offset by increased employer contributions. The Predecessor contributed $6.7 million and $11.9 million to its pension plans in 2014 and 2013, respectively.

 

102

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Columbia Pipeline Partners LP

 

The Predecessor’s funded status for its other postretirement benefit plans improved by $9.4 million to an overfunded status of $102.7 million primarily due to plan amendments in 2014 offset by a decrease in the discount rate from the prior measurement date. The Predecessor contributed approximately $10.8 million and $10.6 million to its other postretirement benefit plans in 2014 and 2013, respectively. No amounts of the Predecessor’s pension or other postretirement benefit plans’ assets are expected to be returned to the Predecessor in 2015.

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
		2014				2013				2014				2013
Weighted-average assumptions to determine benefit obligation
Discount Rate			3.64	%			4.34	%			3.95	%			4.74	%
Rate of Compensation Increases			4.00	%			4.00	%			—				—
Health Care Trend Rates
Trend for Next Year			—				—				6.90	%			7.09	%
Ultimate Trend			—				—				4.50	%			4.50	%
Year Ultimate Trend Reached			—				—				2021				2021

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			$	(0.1	)
Effect on accumulated postretirement benefit obligation			3.4				(3.1	)

The Predecessor does not expect to make any material contributions to its pension plans in 2015. Contributions of approximately $9.9 million are expected to be made to its postretirement medical and life plans in 2015.

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)
2015		$	21.8			$	7.8			$	0.3
2016			24.5				7.6				0.3
2017			24.2				7.4				0.3
2018			25.3				7.5				0.3
2019			25.6				7.4				0.3
2020-2024			139.8				36.4				1.5

 

103

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Columbia Pipeline Partners LP

 

The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended December 31, 2014, 2013, and 2012:

 

		Pension Benefits												Other Postretirement Benefits
		2014				2013				2012				2014				2013				2012
		(in millions)
Components of net periodic benefit
Cost (Income)
Service cost		$	4.8			$	4.8			$	5.9			$	1.1			$	1.5			$	1.5
Interest cost			13.7				12.6				14.6				4.6				4.9				5.9
Expected return on assets			(23.8	)			(22.0	)			(22.6	)			(16.5	)			(13.5	)			(11.6	)
Amortization of prior service (credit) cost			(1.0	)			(0.9	)			(0.9	)			0.1				0.1				0.3
Recognized actuarial loss (income)			6.6				10.6				11.0				(0.1	)			1.0				0.7
Net Periodic Benefit Cost (Income)		$	0.3			$	5.1			$	8.0			$	(10.8	)		$	(6.0	)		$	(3.2	)
Settlement loss			—				12.4				—				—				—				—
Total Net Periodic Benefit Cost (Income)		$	0.3			$	17.5			$	8.0			$	(10.8	)		$	(6.0	)		$	(3.2	)

The decrease in the actuarially-determined pension benefit cost is due primarily to the settlement loss in 2013, increasing interest rates, and favorable asset returns. The actuarially-determined other post-retirement benefit plan income was $10.8 million in 2014 and $6.0 million in 2013.

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
		2014				2013				2012				2014				2013				2012
Weighted-average assumptions to determine net periodic benefit cost
Discount Rate			4.34	%			3.36	%			4.60	%			4.74	%			3.92	%			4.88	%
Expected Long-Term Rate of Return on Plan Assets			8.30	%			8.30	%			8.30	%			8.14	%			8.15	%			8.17	%
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 2014 pension benefits cost. This is primarily based on asset mix and historical rates of return.

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
		2014				2013				2014				2013
		(in millions)
Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities
Net prior service cost		$	—			$	—			$	—			$	0.2
Net actuarial (gain)/loss			24.4				(38.2	)			11.7				(38.8	)
Less: Settlement loss			—				(12.4	)			—				—
Less: amortization of prior service cost			1.0				0.9				—				(0.1	)
Less: amortization of net actuarial gain			(6.6	)			(10.6	)			—				(1.0	)
Total recognized in regulatory assets/liabilities		$	18.8			$	(60.3	)		$	11.7			$	(39.7	)
Amount recognized in net periodic benefit cost and regulatory assets/liabilities		$	19.1			$	(42.8	)		$	0.9			$	(45.7	)

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 2015 for the pension plans are $8.1 million, $(1.0) million and zero, respectively, and for other postretirement benefit plans are zero, $0.1 million and zero, respectively.

 

 

104

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Columbia Pipeline Partners LP

 

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 and current portion of 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, 2014 and 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:

 

		At December 31,
		Carrying Amount 2014				Estimated Fair Value 2014				Carrying Amount 2013				Estimated Fair Value 2013
		(in millions)
Current portion of long-term debt—affiliated		$	115.9			$	120.0			$	—			$	—
Long-term debt—affiliated			1,472.8				1,550.4				819.8				835.7

 

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.

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, 2014, tax years through 2010 have been audited and are effectively closed to further assessment, except for immaterial carryforward amounts. The audits of tax years 2011, 2012, 2013, and 2014 under the Compliance Assurance Program (“CAP”) are in process. As of December 31, 2014, 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.

 

105

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Columbia Pipeline Partners LP

 

As of December 31, 2014 and 2013, the Predecessor has a liability recorded 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.

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, 2014. The total liability at the Predecessor related to the facilities subject to remediation was $1.8 million and $8.7 million at December 31, 2014 and 2013, 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.

On January 31, 2015, the recovery mechanism for PCB remediation costs ceased. Any amounts recovered over amounts incurred will be refunded to customers in association with the final regulatory filing with the FERC, which is expected in May 2015.

D. Operating Lease Commitments. The Predecessor leases assets in several areas of its operations. Payments made in connection with operating leases were $14.9 million in 2014, $13.4 million in 2013 and $10.7 million in 2012, 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(1)
		(in millions)
2015		$	4.7
2016			3.4
2017			5.8
2018			5.5
2019			5.3
After			24.9
Total future minimum payments		$	49.6

 

(1)

Operating lease expense was $14.9 million in 2014, $13.4 million in 2013 and $10.7 million in 2012, 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.

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 2015 to 2025, require the Predecessor to pay fixed monthly charges.

 

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The estimated aggregate amounts of minimum fixed payments at December 31, 2014, were:

 

		Pipeline Service Agreements
		(in millions)
2015		$	42.7
2016			42.0
2017			38.6
2018			25.9
2019			19.2
After			56.3
Total future minimum payments		$	224.7

 

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, 2012		$	(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	)
Other comprehensive income before reclassifications			—				—				—
Amounts reclassified from accumulated other comprehensive income			1.0				—				1.0
Net current-period other comprehensive income			1.0				—				1.0
Balance as of December 31, 2014		$	(16.6	)		$	(0.1	)		$	(16.7	)

(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 $16.6 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 $16.6 million and $17.6 million at December 31, 2014 and December 31, 2013, respectively, is included in unrealized losses on cash flow hedges above.

 

 

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15.	Other, Net

 

		Year Ended December 31,
		2014				2013				2012
		(in millions)
AFUDC Equity		$	11.0			$	6.8			$	1.4
Miscellaneous(1)			(2.2	)			10.8				0.1
Total Other, net		$	8.8			$	17.6			$	1.5

⁽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 for the periods presented.

At December 31, 2014, 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, 2014, 2013 and 2012:

 

		Year Ended December 31,
		2014				2013				2012
		(in millions)
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities		$	78.5			$	53.1			$	77.2
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts		$	53.6			$	39.5			$	32.4
Cash paid for income taxes			21.5				10.2				81.7

 

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, 2014, 2013 and 2012. Washington Gas and Light, a non-affiliated entity, accounted for greater than 10% of total operating revenues in the year ended December 31, 2012. 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, 2014, 2013 and 2012:

 

		2014								2013								2012
		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		$	168.5				12.5	%		$	167.5				14.2	%		$	172.4				17.2	%
Washington Gas and Light			116.1				8.6	%			104.6				8.9	%			107.1				10.7	%

 

 

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19.	Quarterly Financial Data (Unaudited)

 

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
2014		(in millions)
Total Operating Revenues		$	345.5			$	343.4			$	317.6			$	340.4
Operating Income			158.5				103.2				93.8				133.2
Net Income			92.5				59.0				53.2				64.4
2013
Total Operating Revenues		$	301.3			$	273.7			$	282.6			$	321.8
Operating Income			133.1				88.4				98.4				119.7
Net Income			78.3				59.1				57.8				71.7

 

20.	Subsequent Event

Closing of Initial Public Offering. On February 11, 2015, the Partnership completed its initial public offering of 53,833,107 common units representing limited partnership interests, constituting approximately 53.5% of the Partnership’s outstanding limited partnership interests. The Partnership received approximately $1,170.0 million of net proceeds from the initial public offering. CEG owns the general partner of the Partnership, all of the Partnership’s subordinated units and the incentive distribution rights. The assets of the Partnership consist of a 15.7% limited partner interest in Columbia OpCo, which consists of substantially all of the Columbia Pipeline Group Operations segment.

In conjunction with the closing of the initial public, the Partnership entered into a $500.0 million revolving credit facility, of which $50 million will be available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures and the funding of capital calls. The facility is guaranteed by NiSource, CPG, CEG, OpCo GP and Columbia OpCo.

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our principal executive officer and principal financial officer are responsible for evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Management’s Report on Internal Control over Financial Reporting

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Controls

There have been no changes in the Predecessor’s internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to affect, the Predecessor’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

 

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

We are managed by the directors and executive officers of our general partner, CPP GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. NiSource indirectly owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Neither we nor our subsidiaries have any employees. Our general partner is responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner.

Directors and Executive Officers of CPP GP LLC

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The directors and executive officers of our general partner are listed below.

 

Name		Age				Position With Our General Partner
Robert C. Skaggs, Jr.			60			Director and Chief Executive Officer
Glen L. Kettering			60			Director and President
Stephen P. Smith			53			Director, Chief Financial Officer and Chief Accounting Officer
Robert E. Smith			45			Director, General Counsel and Corporate Secretary
Stanley G. Chapman, III			49			Director and Chief Commercial Officer
Thomas W. Hofmann			63			Director

Robert C. Skaggs, Jr. Mr. Skaggs was appointed to our board of directors in February 2015. 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 CPG effective at the time of the spin-off.

Glen L. Kettering. Mr. Kettering was appointed to our board of directors in February 2015. 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

 

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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 CPG effective at the time of the spin-off.

Stephen P. Smith. Mr. Smith was appointed to our board of directors in July 2009. Mr. Smith currently 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 CPG effective at the time of the spin-off.

Robert E. Smith. Mr. Smith was appointed to our board of directors in February 2015. 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 CPG effective at the time of the spin-off.

Stanley G. Chapman, III. Mr. Chapman was appointed to our board of directors in February 2015. Mr. Chapman 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 CPG effective at the time of the spin-off.

Thomas W. Hofmann. Mr. Hofmann was appointed to our board of directors and as chairman of our audit committee in February 2015. 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 selected to serve as 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 has appointed Mr. Hofmann as our initial independent director.

 

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Committees of the Board of Directors

The board of directors of our general partner has 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.

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. In connection with our initial public offering, Mr. Hofmann was appointed chairman and sole member of our audit committee. The board of directors has determined that Mr. Hofmann is financially literate, is the audit committee financial expert and is “independent” under the standards of the NYSE and SEC regulations currently in effect.

The audit committee assists 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 has 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 is also 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 CPG). 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, CPG 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.

Executive Sessions of Non-Management Directors; Procedures for Contacting the Board of Directors

The board of directors of our general partner plans to hold regular executive sessions in which the three independent directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the independent directors. The rules of the NYSE require that one of the independent directors must preside over each executive session. The chairman of our audit committee will preside over each executive session.

Corporate Governance

The board of directors of our general partner has adopted a Financial Code of Ethics that applies to the chief executive officer, chief financial officer, controller, treasurer and all other persons performing similar functions on behalf of our general partner and us. Amendments to or waivers from the Financial Code of Ethics will be disclosed on our Internet website in accordance with the rules and regulations of the SEC and the listing requirements of the NYSE. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.

 

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We make available, free of charge, an electronic copy of the Financial Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter and Code of Business Conduct and Ethics on our website at http://www.columbiapipelinepartners.com. Unitholders may also obtain copies of these documents upon written request to Columbia Pipeline Partners LP, Investor Relations, 5151 San Felipe St., Suite 2500, Houston, Texas 77056.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10 percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. During the year ended December 31, 2014, we did not have any registered class of equity securities.

 

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ITEM 11. EXECUTIVE COMPENSATION

Prior to our initial public offering, we and our general partner had no material assets or operations. Accordingly, our general partner did not accrue any obligations with respect to compensation of its directors and executive officers for any periods prior to our initial public offering, including with respect to our 2014 fiscal year. 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, is 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 is not entitled to 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 are required to 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.

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 are 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. Our executive officers do not receive additional compensation for their service as such.

Long-Term Incentive Plan

In connection with our initial public offering, our general partner adopted the Columbia Pipeline Partners LP Long-Term Incentive Plan (“LTIP”). The LTIP provides 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, except with respect to phantom units granted in connection with retainers provided to our non-employee directors, as described below under “Compensation of Directors”, to date we have not made any grants of awards pursuant to the LTIP.

Historical Compensation

As previously discussed, we are a wholly owned subsidiary of our sponsor formed to acquire, at the closing of our initial public offering, portions of several different parts of our sponsor’s business. Neither we nor our general partner incurred any cost or liability with respect to compensation of our executive officers prior to the closing of our initial public offering, including during the 2014 fiscal year. Accordingly, we have no historical compensation information to present.

 

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Compensation Committee Report

Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K and, based on these reviews and discussions, recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

The board of directors of CPP GP LLC:

Robert C. Skaggs, Jr.

Stephen P. Smith

Glen L. Kettering

Robert E. Smith

Stanley G. Chapman, III

Thomas W. Hofmann

Compensation of Directors

Officers or employees of our sponsor or its affiliates who also serve as directors of our general partner do not receive additional compensation for such service.

No directors of our general partner received compensation for such service during the 2014 fiscal year.

In connection with our initial public offering, our general partner implemented an annual retainer compensation package for our non-employee directors valued at approximately $150,000 (pro rated for partial years), of which approximately $60,000 will be paid in the form of an annual cash retainer and the remaining $90,000 retainer fee will be paid in a grant of phantom unit awards under the LTIP.

In addition, our general partner has approved an additional cash retainer for our 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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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth the beneficial ownership of common units and subordinated units of the Partnership held by:

 

•

our general partner;

 

•

beneficial owners of 5% or more of our common units;

 

•

each director and named executive officer; and

 

•

all of our directors and executive officers as a group.

The following table includes common units that our directors and executive officers have purchased through the directed unit program. The percentage of our units beneficially owned is based on a total of 53,833,107 common units and 46,811,398 subordinated units outstanding.

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)		—			— %				46,811,398				100%				50.0%
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.

 

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The following table sets forth, as of January 30, 2015, the number of shares of common stock of NiSource owned by each director and named executive officer of our general partner and by all directors 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			85,371	(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)			966,734				—	%

 

*	Less than 1%

 

(1)	Does not include 128,370 shares underlying performance stock units that are subject to vesting in 2015 to the extent that performance objectives are achieved.

 

(2)	Does not include 21,395 shares underlying performance stock units that are subject to vesting in 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 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 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 2015 to the extent that performance objectives are achieved.

 

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Equity Compensation Plan Information

In connection with the consummation of our initial public offering on February 11, 2015, the board of directors of our general partner adopted the Columbia Pipeline Partners LP Long Term Incentive Plan. The following table provides certain information with respect to this plan as of February 11, 2015:

 

		Number of Securities to be Issued Upon Exercise  of Outstanding Options, Warrants and Rights(1) (a)				Weighted -Average Exercise Price of Outstanding Options, Warrants  and Rights (b)				Number of Securities Remaining Available for Future Issuance Under Equity  Compensation Plans (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by unitholders			—				n/a				—
Equity compensation plans not approved by unitholders			—				n/a				9,000,000
Total			—				n/a				9,000,000

 

(1)The long-term incentive plan currently permits the grant of awards covering an aggregate of 9 million units

 

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of February 11, 2015, CEG and its affiliates owned 46,811,398 subordinated units representing an aggregate 46.5% limited partner interest in us. CEG beneficially owns all of our subordinated units and all of our incentive distribution rights. CEG owns 84.3% of the limited partner interests in Columbia OpCo. In addition, CEG owns 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.

Historical Transactions

Prior to the initial public 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.

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, before our initial public offering, 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		•       all 46,811,398 subordinated units;   •       our incentive distribution rights; and   •       we received $1,170.0 million of net proceeds from our initial public offering (after deducting the underwriting discount, the structuring fee of $8.2 million paid to Barclays Capital Inc. and Citigroup Global Markets Inc., and expenses of this offering). We used the net proceeds to purchase an additional approximate 8.4% limited partner interest in Columbia OpCo. Columbia OpCo used $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 used the remaining proceeds it received from us to fund expansion capital expenditures. The approximate 8.4% interest in Columbia OpCo purchased with the proceeds from the offering, when combined with an approximate 7.3% interest in Columbia OpCo contributed to us in connection with the formation transactions, resulted in our ownership of a 15.7% limited partner interest in Columbia OpCo following the closing of the offering.

 

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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 all of our subordinated units (46.5% 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 $31.4 million on their common and subordinated units (or $31.4 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.
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.
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

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not 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, were paid from the proceeds of the offering.

 

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Omnibus Agreement

At the closing of our initial public offering, we entered into an omnibus agreement with CEG, our general partner, Columbia OpCo and others that addressed CEG’s obligation to indemnify us for certain liabilities and our obligation to indemnify CEG for certain liabilities. Certain aspects of the agreement include:

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.

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 84.3% 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 84.3% 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 CPG to violate its covenants under the tax sharing agreement that CPG may enter into with NiSource in connection with the spin-off. In addition, we will agree not to take any action that could cause CPG 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.

 

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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.

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 CPG, Columbia OpCo will be required to guarantee any future indebtedness that CPG incurs. In addition, at our request, CPG 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 CPG 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 CPG 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 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.

 

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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 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 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 has 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

In connection with the closing of our initial public offering, the board of directors of our general partner adopted policies for the review, approval and ratification of transactions with related persons. The board adopted a written code of business conduct and ethics, under which a director is 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 will 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.

 

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Executive officers are required to avoid conflicts of interest unless approved by the board of directors of our general partner.

As a result of the code of business conduct and ethics being adopted in connection with the closing of our initial public offering, the transactions described above were not reviewed according to such procedures.

Director Independence

See “Item 10. Directors, Executive Officers and Corporate Governance” for information regarding the directors of our general partner and independence requirements applicable for the Board of Directors of our general partner and its committees.

 

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

We have engaged Deloitte & Touche LLP as our independent registered public accounting firm. The following table sets forth fees we have paid to Deloitte & Touche LLP for the year ended December 31, 2014.

 

Audit and Non-Audit Fees
		2014
		(in millions)
Audit Fees(1)		$1.7
Audit-Related Fees(2)		-
Tax Fees(3)		-
All Other Fees(4)		-
Total		$1.7

 

(1)

Audit fees relate to professional services rendered in connection with the audit of our 2014 annual financial statements on our Form 10-K as well as the audit of our annual financial statements and quarterly review of financial statements included in our Registration Statement on Form S-1 filed with the SEC.

(2)

Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits, agreed upon procedures required to comply with financial, accounting or regulatory reporting and assistance with internal control documentation requirements.

(3)	Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.

(4)	All other fees represent fees for services not classifiable under the other categories listed in the table above.

Audit Committee Pre-Approval Policies and Procedures

The audit committee charter of the board of directors of our general partner, which is available on our website at http://www.columbiapipelinepartners.com, requires the audit committee to pre-approve all audit services and permitted non-audit services (other than de minimis non-audit services as defined by the Sarbanes-Oxley Act of 2002) to be provided by our independent registered public accounting firm. The Audit Committee may form and delegate authority to subcommittees consisting of one or more members when appropriate, including the authority to grant preapprovals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant preapprovals shall be presented to the full Audit Committee at its next scheduled meeting for ratification. Since our audit committee was not established until February 2015, our board of directors pre-approved all services reported in the audit, audit-related, tax, and all other fees categories above.

 

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

The following financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8, “Financial Statements and Supplementary Data.”

 

Index			Page
Columbia Pipeline Partners LP
Audited Balance Sheets
Report of Independent Registered Public Accounting Firm			71
Balance Sheets as of December 31, 2014 and June 30, 2014			72
Notes to the Balance Sheets			73
Columbia Pipeline Partners LP Predecessor
Audited Historical Financial Statements
Report of Independent Registered Public Accounting Firm			74
Combined Balance Sheets as of December 31, 2014 and 2013			75
Combined Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012			76
Combined Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012			77
Combined Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			78
Combined Statements of Parent Net Equity for the Years Ended December 31, 2014, 2013 and 2012			79
Notes to Combined Financial Statements			80
Exhibits

The exhibits filed herewith as a part of this report on Form 10-K are listed on the Exhibit Index immediately following the signature page. Each management contract or compensatory plan or arrangement of the Partnership, listed on the Exhibit Index, is separately identified by an asterisk.

Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of the Partnership’s subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees to furnish a copy of any such instrument to the SEC upon request.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

/S/    ROBERT C. SKAGGS, JR.		Director and Chief Executive Officer (Principal Executive Officer)		Date:        February 18, 2015
Robert C. Skaggs, Jr.
/S/    STEPHEN P. SMITH		Director, Chief Financial Officer and Chief Accounting Officer (Principal Financial and Principal Accounting Officer)		Date:        February 18, 2015
Stephen P. Smith
/S/    GLEN L. KETTERING		Director and President		Date:        February 18, 2015
Glen L. Kettering
/S/    ROBERT E. SMITH		Director, General Counsel and Corporate Secretary		Date:        February 18, 2015
Robert E. Smith
/S/    STANLEY G. CHAPMAN, III		Director and Chief Commercial Officer		Date:        February 18, 2015
Stanley G. Chapman, III
/S/    THOMAS W. HOFMANN		Director		Date:        February 18, 2015
Thomas W. Hofmann

 

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EXHIBIT INDEX

 

EXHIBIT NUMBER										DESCRIPTION OF ITEM
			3.1				—			Certificate of Limited Partnership of NiSource Energy Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on September 29, 2014).
			3.2				—			Certificate of Amendment to Certificate of Limited Partnership of NiSource Energy Partners, L.P. (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on November 12, 2014).
			3.3				—			First Amended and Restated Agreement of Limited Partnership of Columbia Pipeline Partners LP, dated as of February 11, 2015 (Incorporated by reference to Exhibit 3.1 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			4.1				—			Registration Rights Agreement, dated as of February 11, 2015, by and between Columbia Pipeline Partners LP and Columbia Energy Group (Incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			10.1				—			Contribution, Conveyance and Assumption Agreement, dated as of February 11, 2015, by and among NiSource Inc., NiSource Finance Corp., Columbia Pipeline Group, Inc., Columbia Energy Group, Columbia Gas Transmission, LLC, Columbia Gulf Transmission, LLC, Columbia Hardy Holdings, LLC, Columbia Hardy Corporation, Columbia Midstream & Minerals Group, LLC, Columbia Midstream Group, LLC, Columbia Pipeline Partners LP, CPP GP LLC, CPG OpCo LP and CPG OpCo GP LLC (Incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			10.2				—			Omnibus Agreement, dated as of February 11, 2015, by and among Columbia Energy Group, CPP GP LLC, Columbia Pipeline Group, Inc. and Columbia Pipeline Partners LP (Incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			10.3†				—			Columbia Pipeline Partners LP Long Term Incentive Plan (Incorporated by reference to Exhibit 4.4 to the Partnership’s Form S-8 (File No. 333-202021) filed on February 11, 2015).
			10.4				—			Service Agreement, dated as of February 11, 2015, by and between Columbia Pipeline Partners LP, its subsidiaries, affiliates and associates and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			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. (Incorporated by reference to Exhibit 10.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on December 10, 2014).
			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(Incorporated by reference to Exhibit 10.6 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on December 10, 2014).
			10.7				—			Tax Sharing Agreement, dated as of February 11, 2015, by and among NiSource Inc., Columbia Pipeline Partners LP and CPG OpCo LP (Incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K (File No. 001-36835) filed on February 11, 2015).
			10.8*				—			Trademark License Agreement, dated as of February 11, 2015, by and between NiSource Corporate Services Company and Columbia Pipeline Group Services Company.

 

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			10.9				—			Amended and Restated Agreement of Limited Partnership of CPG OpCo LP, dated as of February 11, 2015, (Incorporated by reference to Exhibit 10.5 to the Partnership’s Form 8-K (File No. 3001-36835) filed on February 11, 2015).
			10.10†				—			Form of Columbia Pipeline Partners LP Phantom Unit Agreement (Incorporated by reference to Exhibit 4.5 to the Partnership’s Form S-8 (File No. 333-202021) filed on February 11, 2015).
			21.1*				—			List of Subsidiaries of Columbia Pipeline Partners LP.
			23.1*				—			Consent of Deloitte & Touche LLP
			23.2*				—			Consent of Deloitte & Touche LLP
			31.1*				—			Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31.2*				—			Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32.1*				—			Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32.1*				—			Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

†	Management contract or compensatory plan or arrangement of Columbia Pipeline Partners LP.

 

*	Exhibit filed herewith.

 

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