Attached files

file filename
EX-32.2 - EXHIBIT 32.2 - Columbia Pipeline Partners LPcppl-20151231xex322.htm
EX-32.1 - EXHIBIT 32.1 - Columbia Pipeline Partners LPcppl-20151231xex321.htm
EX-31.2 - EXHIBIT 31.2 - Columbia Pipeline Partners LPcppl-20151231xex312.htm
EX-23.1 - EXHIBIT 23.1 - Columbia Pipeline Partners LPcppl-20151231xex231.htm
EX-31.1 - EXHIBIT 31.1 - Columbia Pipeline Partners LPcppl-20151231xex311.htm
EX-21.1 - EXHIBIT 21.1 - Columbia Pipeline Partners LPcppl-20151231xex211.htm

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, 2015
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
 
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 þ   No ¨
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 þ   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
The aggregate market value of Common Units (based upon the June 30, 2015, closing price of $25.20 on the New York Stock Exchange) held by non-affiliates was approximately $1,353,717,666.
At February 10, 2016, there were 53,834,784 Common Units and 46,811,398 Subordinated Units outstanding.




CONTENTS
 
 
 
Page
No.
 
 
Item 1 and 2.
Item 1A.    
Item 1B.
Item 3.
Item 4.
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
Item 15.

2


Columbia Pipeline Partners LP



DEFINED TERMS

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

Affiliates and Subsidiaries of Columbia Pipeline Partners LP
CEG
Columbia Energy Group
CEVCO
Columbia Energy Ventures, LLC
CNS Microwave
CNS Microwave, LLC
Columbia Gas Transmission
Columbia Gas Transmission, LLC
Columbia Gulf
Columbia Gulf Transmission, LLC
Columbia Midstream
Columbia Midstream Group, LLC
Columbia OpCo
CPG OpCo LP
CPG
Columbia Pipeline Group, Inc.
CPGSC
Columbia Pipeline Group Services Company
Hardy Storage
Hardy Storage Company, LLC
Millennium Pipeline
Millennium Pipeline Company, L.L.C.
MLP GP
CPP GP LLC
OpCo GP
CPG OpCo GP LLC
Pennant
Pennant Midstream, LLC
 
 
Abbreviations and Definitions
 
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 and one-time transaction costs, less equity earnings in 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 and borrowed funds until a project is placed into operation
AOC
Administrative Order by Consent
AOCI
Accumulated Other Comprehensive Income (Loss)
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Btu
British Thermal Unit
CAA
Clean Air Act
CCRM
Capital Cost Recovery Mechanism
condensate
A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon functions
DOT
Department of Transportation
Dth/d
Dekatherms per day
end-user markets
The ultimate users and consumers of transported energy products
EIA
U.S. Energy Information Administration
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles
Hilcorp
Hilcorp Energy Company
HP
Horsepower

3


Columbia Pipeline Partners LP



DEFINED TERMS (continued)

IPO
Initial public offering of Columbia Pipeline Partners LP, which was completed on February 11, 2015
LDC
Local distribution companies are 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
NAAQS
National Ambient Air Quality Standards
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)
NiSource
NiSource Inc.
NiSource Corporate Services
NiSource Corporate Services Company
NiSource Finance
NiSource Finance Corp.
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
Partnership Distributable Cash Flow
A supplemental non-GAAP financial measure defined by us as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to Separation and any other known differences between cash and income.
PHMSA
Pipeline and Hazardous Materials Safety Administration
Piedmont
Piedmont Natural Gas Company, Inc.
play
A proven geological formation that contains commercial amounts of hydrocarbons
ppb
parts per billion
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
Williams Partners
Williams Partners L.P.

 

4


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:
changes in general economic conditions;
competitive conditions in our industry;
actions taken by third-party operators, processors and transporters;
the demand for natural gas storage and transportation services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to transporting, storing and gathering natural gas;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
large customer defaults;
changes in the availability and cost of capital;
changes in tax status;
the effects of existing and future laws and governmental regulations;
the effects of future litigation; and
certain factors discussed elsewhere in this 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.


5


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 for periods prior to the IPO, 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, or in reference to the period subsequent to the IPO, refer to Columbia Pipeline Partners LP and its subsidiaries. We refer to our general partner, CPP GP LLC, as our “general partner” and refer to Columbia Pipeline Group Inc. and its subsidiaries other than us and our general partner as “CPG.” 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 CPG, which historically owned substantially all of the natural gas transmission and storage assets of CPG. After the closing of our IPO, 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 IPO 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 2 of Notes to Consolidated and Combined Financial Statements for further discussion of the Offering.
Separation of Columbia Pipeline Group
On July 1, 2015, NiSource distributed, pursuant to an effective registration statement on Form 10, 317.6 million shares of CPG, on share of common stock for every share of NiSource common stock held by NiSource stockholders on the record date (the "Separation"). CPG directly owns 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.
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.

6

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



The following is a simplified diagram of our organization and ownership structure as of December 31, 2015. The ownership percentages referred to below illustrate the relationships among us, Columbia OpCo, our general partner, CEG, CPG and its affiliates:
As part of the transactions in connection with our IPO, 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.
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

7

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



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 20, “Segments of Business” in Item 8, Financial Statements and Supplementary Data for further discussion regarding our segment.
Description of Businesses and Properties
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 11,272 miles of natural gas transmission pipeline. It has a transportation capacity of approximately 10 MMDth/d, transports an average of approximately 4.0 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 819,500 acres of underground storage, 3,432 storage wells, which includes 35 storage fields in four states with approximately 627.5 MMDth in total operational capacity, with approximately 290 MMDth of working gas capacity.
Columbia GulfThe 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 interstate and 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, which transports an average of 1.1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline, and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline. 
Hardy Storage Joint Venture. We own a 49% ownership interest in Hardy Storage, 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 approximately 123 miles of

8

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and also owns a 47.5% ownership interest in Pennant, which owns approximately 49 miles of natural gas gathering pipeline infrastructure, a cryogenic processing plant and a 36 mile NGL pipeline. Columbia Midstream supports the growing production in the Utica and Marcellus resource plays.
CEVCO. CEVCO 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 three 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 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.
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 have recently placed into service or are currently pursuing the following significant expansion projects:
Chesapeake LNG. This approximately $28 million project was placed into service in the second quarter of 2015 and replaced 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives.
Big Pine Expansion. We are investing approximately $75 million to extend the Big Pine pipeline and add compression facilities that will add incremental capacity. The project will support Marcellus shale production in western Pennsylvania. The project piping was placed into service in the third quarter of 2015 and we expect the compression to be placed into service in the second quarter of 2016.

9

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



East Side Expansion. This project provides access for production from the Marcellus shale to northeastern and mid-Atlantic markets. The approximately $295 million project added 312,000 Dth/d of capacity and was placed into service in the fourth quarter of 2015.
Washington County Gathering. A producer has contracted with us to build an approximately 20 mile gas gathering system in southwestern Pennsylvania. The initial project went into service during the third quarter of 2015 and we expect to invest approximately $120 million through 2018.
Kentucky Power Plant Project. We expect to invest approximately $25 million to construct 2.7 miles of 16-inch pipeline and other facilities to a power plant near Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service and is expected to be placed into service in the second quarter of 2016.
Gibraltar Pipeline Project. We expect to invest approximately $270 million to construct an approximately 1 MMDth/d dry gas header pipeline in southwest Pennsylvania. We expect this to be the first of multiple phases with a projected initial in-service date in the fourth quarter of 2016.
Utica Access Project. We expect to invest approximately $50 million to construct 4.7 miles of 24-inch pipeline to provide 205,000 Dth/d of new firm transportation to provide Utica production access to liquid trading points on Columbia Gas Transmission's system. This project is expected to be placed into service in the fourth quarter of 2016.
Leach XPress. This project will provide approximately 1.5 MMDth/d of capacity from the Marcellus and Utica production regions to the Leach compressor station located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. We expect the project, which involves an estimated investment of approximately $1.4 billion, to be placed into service in the fourth quarter of 2017.
Rayne XPress. This project will transport approximately 1 MMDth/d of southwest Marcellus and Utica production from the Leach, Kentucky interconnect with Columbia Gas Transmission towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. We expect the project, which involves an estimated investment of approximately $380 million, to be placed into service in the fourth quarter of 2017.
Millennium Lateral. We intend to invest approximately $20 million through our ownership stake in Millennium Pipeline to construct approximately 8 miles of 16-inch pipeline to a new power plant situated near Wawayanda, New York. This project will provide up to 127,000 Dth/d of new firm capacity and is expected to be placed into service in the second quarter of 2017.
Cameron Access Project. This project, which involves an investment of approximately $310 million, will provide 800,000 Dth/d of transportation capacity on the Columbia Gulf system to the Cameron LNG export terminal in Louisiana. We expect the project to be placed into service in the first quarter of 2018.
WB XPress. This project, which involves an investment of approximately $850 million, will expand Columbia Gas Transmission's WB system in order to transport approximately 1.3 MMDth/d of Marcellus production to pipeline interconnects and East Coast markets, including access to the Cove Point LNG terminal. We expect this project to be placed into service in the fourth quarter of 2018.
Mountaineer XPress. This approximately $2.0 billion project will provide new takeaway capacity for Marcellus and Utica production. The project will provide up to 2.7 MMDth/d of firm transportation capacity on the Columbia Gas Transmission system. We expect this project to be placed into service in the fourth quarter of 2018.
Gulf XPress. This project will provide 860,000 Dth/d of firm transportation capacity for Marcellus and Utica production on the Columbia Gulf system. This project involves an investment of approximately $0.7 billion and is expected to be placed into service in the fourth quarter of 2018.
Millennium Eastern System Upgrade. We intend to invest approximately $130 million through our ownership stake in Millennium Pipeline to expand eastward flow capacity by 237,500 Dth/d to Ramapo and other nearby points on the system. We expect this project to be placed into service in the fourth quarter of 2018.

10

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



In 2013, the FERC approved the modernization settlement entered into by Columbia Gas Transmission and its customers that provides recovery and return on an investment of up to $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Columbia Gas Transmission placed approximately $319 million in modernization investments into service during 2015. In January 2016, the FERC approved Columbia Gas Transmission's third annual filing for recovery under this program. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016. This extension will allow Columbia Gas Transmission to invest an additional $1.1 billion over an additional three-year period through 2020. This agreement also expands the scope of facility investments covered by the program.
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.

Moreover, new legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital costs, operational delays and costs of operation. For example, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), which authorized funding for federal pipeline safety programs through 2015, directed the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which could result in more stringent safety controls or inspections or additional natural gas and hazardous liquids pipeline safety rulemaking. 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 interstate 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. Although a number of the mandates imposed under the 2011 Act have yet to be acted upon by PHMSA, those mandates continue to have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs in the future. Legislation that would reauthorize federal pipeline safety programs through 2019, referred to as Securing America’s Future Energy: Protecting Infrastructure of Pipelines and Enhancing Safety ("SAFE PIPES"), was approved by the Senate Commerce Committee in December 2015 and will be considered by the U.S. Senate. Among other things, the SAFE PIPES legislation would require PHMSA to conduct an assessment of its inspection process and integrity management programs for natural gas and hazardous liquid pipelines and likely would require PHMSA to pursue those mandates under the 2011 Pipeline Safety Act that have not yet been acted upon. More recently, in February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators. The bulletin recommends that operators review operations to identify the potential for leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in piping, tubing, casing, valves, and other associated facilities. The bulletin further advises operators to review storage facility locations and operations of shut-off and isolation systems, and review and update emergency plans as necessary. Finally, the advisory directs compliance with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommends the voluntary implementation of certain industry-recognized recommended practices for natural gas storage facilities. PHMSA indicated when it issued the advisory bulletin that additional regulations related to safety standards for natural gas storage facilities are likely forthcoming. At this time, we cannot predict the impact of any future regulatory actions in this area.

11

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



In addition, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, several 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 2016. 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.
For additional information regarding pipeline safety, see “Risk Factors” under Item 1A of this Form 10-K.
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:
The Federal CAA and comparable state laws, which restrict the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, and provides authority for adopting climate change regulatory initiatives. 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.
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.
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.
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, and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States. 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.
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.
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.
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.

12

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



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.
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.
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.

13

Columbia Pipeline Partners LP
ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)



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.
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. Operating revenues for 2015 were approximately 25% in the first quarter, 24% in the second quarter, 24% in the third quarter, and 27% in the fourth quarter.
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 prior to the Separation, accounted for approximately 13% of our total operating revenues for the year ended December 31, 2015. No other customer accounted for greater than 10% of total operating revenue. Please see Note 22, “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
We do not have employees. We are managed by the directors and officers of our general partner. As of December 31, 2015, Columbia OpCo had approximately 1,388 active employees. Of these 1,388 employees, 258 are covered by collective bargaining agreements, 224 of which expire in 2016.
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.

14

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.
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 December 31, 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:
the rates we charge for our transmission, storage and gathering services;
the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;
regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;
legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility;
the imposition of requirements by state agencies that materially reduce the demand of Columbia OpCo’s customers, such as LDCs and power generators, for its pipeline services;
the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;
the creditworthiness of our customers, particularly in light of recent declines in commodity prices;
the level of Columbia OpCo’s operating and maintenance and general and administrative costs;
the level of capital expenditures Columbia OpCo incurs to maintain its assets;
regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region;
successful development of LNG export terminals in the eastern or northeastern U.S., which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system;
changes in insurance markets and the level, types and costs of coverage available, and the financial ability of our insurers to meet their obligations;
changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;
changes in accounting rules and/or tax laws or their interpretations;
nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and
changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.



15

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
the level and timing of capital expenditures we or Columbia OpCo makes;
construction costs;
fluctuations in our or Columbia OpCo’s working capital needs;
our or Columbia OpCo’s ability to borrow funds and access capital markets;
our or Columbia OpCo’s debt service requirements and other liabilities;
restrictions contained in our or Columbia OpCo’s existing or future debt agreements; and
the amount of cash reserves established by our general partner.
Columbia OpCo is a restricted subsidiary and a guarantor under CPG’s credit facilities and guarantees $2.75 billion in aggregate principal amount of CPG’s senior unsecured notes 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. CPG’s credit facility has customary covenants and restrictions on CPG and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facility. On May 22, 2015, CPG sold $2.75 billion in aggregate principal amount of senior notes in a private placement, which such amount is guaranteed by certain of our subsidiaries, including Columbia OpCo. In addition, 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:
make investments and other restricted payments;
incur additional indebtedness or issue preferred stock;
create liens;
sell all or substantially all of its assets or consolidate or merge with or into other companies; and
engage in transactions with affiliates.
These covenants or any more restrictive covenants agreed to by 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.



16

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



Columbia OpCo is a party to a money pool agreement with CPG, which provides Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. The money pool is 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.
Columbia OpCo and its subsidiaries have entered 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 is 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 agreement. 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 subsidiaries 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 subsidiaries 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:
the fees it charges and the margins it realizes for its services;
regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility;
the level of its operating, maintenance and general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash Columbia OpCo will have available for distribution to its partners, including us, also will depend on other factors, such as:
the level of capital expenditures it makes;
its debt service requirements and other liabilities;
restrictions contained in its debt agreements, including CPG’s credit facility;

17

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



its ability to borrow funds;
fluctuations in its working capital needs;
the cost of acquisitions, if any; and
the amount of cash reserves established by it.
Our future business opportunities may be limited as a result of our agreement with CPG to refrain from taking any action that would prevent CPG from complying with the tax sharing agreement that entered into with NiSource in connection with the Separation.
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 entered into with NiSource in connection with the Separation. Under such tax sharing agreement, CPG has agreed to take certain actions, or refrain from taking certain actions, to ensure that the Separation 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 has agreed that, for the two years following the Separation, 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. 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 Separation, which may adversely impact our financial condition, results of operations and ability to make distributions to you. Please see “Business and Properties-Separation 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:
service interruptions or increased downtime associated with our projects, including the reversal of Columbia Gulf’s pipelines;
a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the project or acquisition;
an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits, among other factors;
the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;
the diversion of our management’s attention from other business concerns;
mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, including synergies and potential growth;
an inability to successfully integrate acquired assets or the businesses we build;
an inability to receive cash flows from a newly built asset until it is operational; and
unforeseen difficulties operating in new product areas or new geographic areas.
If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per unit, our ability to make distributions to you may be reduced.


18

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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 acquire or 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 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.

We depend on certain key customers for a significant portion of our revenues and to anchor our portfolio of growth projects. The loss of key customers could have a material adverse effect on our business, results of operations, financial condition, growth plans and ability to pay distributions to our unitholders.

We are subject to risks of loss resulting from nonperformance by our customers. We depend on certain key customers for a significant portion of our revenues. In addition, we are making significant capital expenditures to expand our existing assets and construct new energy infrastructure based on long-term contracts with customers, including natural gas producers who may be adversely impacted by sustained low commodity prices. Our credit procedures and policies and credit support arrangements may not be adequate to fully eliminate customer credit risk. Further, we may not be able to effectively remarket capacity related to nonperforming customers. The deterioration in the creditworthiness of our customers or the failure of our customers to meet their contractual obligations could have a material adverse effect on our business, results of operations, financial condition, growth plans and ability to pay distributions to our unitholders.

19

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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 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 subleased the production rights in three storage fields and have also contributed our production rights in one other field. We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:
the timing and amount of capital expenditures;
the timing of initiating the drilling and recompleting of wells;
the extent of operating costs;
selection of technology and drilling and completion methods; and

20

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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 2015 and 2014, natural gas prices remained relatively low, as well as a decrease in oil and natural gas liquids prices, leading some producers to announce significant reductions to their drilling plans. A significant reduction in the level of production on our properties could adversely affect on 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, 2015, Columbia Gas Transmission has remaining $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. For example, in October 2015, the U.S. Environmental Protection Agency (“EPA”) issued a final rule under the federal Clean Air Act (“CAA”), lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations, which could apply to our or our customers’ operations. Compliance with this final rule could, among other things, require installation of new emission controls, result in longer permitting timelines, and significantly increase capital expenditures and operating costs. In another example, the EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the Clean Water Act (“CWA”) over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. 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.
In addition, a number of state and regional legal initiatives have emerged in recent years that seek to reduce greenhouse gas (“GHG”) emissions and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore processing sources, such as emissions from gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the U.S. on an annual basis. On an international level, the United States is one of almost 200 nations that agreed on December 12, 2015 to

21

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets. It is not possible at this time to predict how or when the United States might impose legal requirements as a result of this international agreement. New regulations or any new federal laws restricting emissions of GHGs from our or our customer operations could result in increased compliance costs and delay or curtail activities that and, in turn, could adversely affect our business. Moreover, any such future laws and regulations that limit emissions of GHGs or that otherwise promote the use of renewable fuels could adversely affect demand for the natural gas our customers produce, which could thereby reduce demand for our services and 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 subsequently could reduce demand for our transportation services.
In another example, pursuant to President Obama’s Strategy to Reduce Methane Emissions from the oil and gas sector by up to 45% from 2012 levels by 2025, in August 2015, the EPA proposed a suite of requirements and draft guidance related to the reduction in methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, including proposed requirements for fugitive emissions of methane and new leak detection and repair requirements. If finalized, these rules and any other 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 noncompliance, 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. Please read “Business and Properties-Regulatory Matters” for more information.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline inspection, 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:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
In addition, the DOT is examining the possibility of expanding integrity management principles beyond high consequence areas in addition to other potential requirements. For example, in March of 2015, the Pipeline Hazardous Materials Safety Administration (“PHMSA”) finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements related to maximum allowable operating pressure calculations. While we cannot predict the outcome of such future regulation at this time, new pipeline safety regulatory requirements could result in significant costs and have the potential to adversely impact our operations.

22

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



There may be additional costs associated with any other major repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. In addition, any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business and Properties-Regulatory Matters” for more information.
We may incur significant costs from time to time in order to comply with DOT regulations regarding the design, strength and testing of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.
DOT regulations govern the design strength and testing of our pipelines. The required design strength and testing of the pipe depends upon the population density near the pipeline. In the event the population density around any specific section of our pipelines increases above levels established by the DOT, we may be required to upgrade the section of our pipelines traversing through the area with pipe of higher strength or, in some cases, retest the pipe, unless a waiver from the DOT is obtained. While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur significant expenses in the future in response to increases in population density near sections of our pipelines.
We may incur significant costs and liabilities to comply with new DOT regulations that are anticipated to be issued in the future.
The 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 condition. For example, in October 2015, PHMSA issued an Advanced Notice of Proposed Rulemaking (“ANPR”) in which the agency seeks public comment on, among other things, extending reporting requirements to all gravity and gathering lines, requiring periodic inline integrity assessments of pipelines and that are located outside of high consequence areas, and requiring the use of leak detection systems on pipelines in all locations, including outside of high consequence areas. While the ANPR relates to the regulation of hazardous liquid lines, it is possible that PHMSA will propose additional requirements on gas pipelines in the future. In addition, legislation that would reauthorize federal pipeline safety programs through 2019, referred to as Securing America’s Future Energy: Protecting Infrastructure of Pipelines and Enhancing Safety (“SAFE PIPES”), was approved by the Senate Commerce Committee and will be considered by the U.S. Senate. Among other things, the SAFE PIPES legislation would require PHMSA to conduct an assessment of its inspection process and integrity management programs for natural gas and hazardous liquid pipelines. While we cannot predict the outcome of these initiatives or future legislative or regulatory efforts, new laws and regulations related to pipeline inspection and integrity management requirements have the potential to adversely impact our business. More recently, in February 2016, PHMSA issued

23

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



an advisory bulletin for natural gas storage facility operators. The bulletin recommends that operators review operations to identify the potential for leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in piping, tubing, casing, valves, and other associated facilities. The bulletin further advises operators to review storage facility locations and operations of shut-off and isolation systems, and review and update emergency plans as necessary. Finally, the advisory directs compliance with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommends the voluntary implementation of certain industry-recognized recommended practices for natural gas storage facilities. PHMSA indicated when it issued the advisory bulletin that additional regulations related to safety standards for natural gas storage facilities are likely forthcoming. At this time, we cannot predict the impact of any future regulatory actions in this area.
Moreover, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas pipelines, which regulations may impose more stringent requirements than those found under federal law. Compliance with these rules and regulations can result in significant maintenance costs; however, at this time, we cannot predict the ultimate cost of such compliance. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our natural gas transportation and storage operations are subject to extensive regulation by the FERC.
Our business operations are subject to extensive regulation by the FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. Compliance with these requirements can be costly and burdensome and the FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC’s regulations. We cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation and storage business or the effect such regulation could have on our business, financial condition and results of operations.
Rate regulation could limit our ability to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.
The rates we can charge for our natural gas transportation and storage operations are regulated by the FERC pursuant to the 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.

24

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



We are exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements. The FERC-approved tariffs of our transmission and storage companies provide for annual filings to adjust the amount of gas retained from customers to eliminate any overages or shortfalls from the prior year. Our gathering companies have contracts that provide for specified levels of fuel retainage, so they may find it necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our gathering systems could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
We could be subject to penalties and fines if we fail to comply with FERC regulations.
Should the FERC find that we have failed to comply with all applicable FERC-administered statutes, rules, regulations, and orders, or the terms of our tariffs on file with the FERC, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005 (“EPAct 2005”), the FERC has civil penalty authority under the NGA and 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 and storage facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and storage facilities 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 and storage facilities on land owned by third parties and governmental agencies for a specific period of time. In certain instances, our rights-of-way may be subordinate to that of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.
Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.
Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:
aging infrastructure, mechanical or other performance problems;
damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;
inadvertent damage from third parties, including from construction, farm and utility equipment;
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
operator error;

25

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



environmental hazards, such as natural gas leaks, product and waste spills, pipeline and tank ruptures, and unauthorized discharges of products, wastes and other pollutants into the surface and subsurface environment, resulting in environmental pollution; and
explosions and blowouts.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations or services. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.
Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.
As of December 31, 2015, we and our subsidiaries had $15 million in outstanding indebtedness under our $500 million credit facility, which is guaranteed by CPG, CEG, OpCo GP and Columbia OpCo. Additionally, Columbia OpCo and its subsidiaries have entered into an intercompany money pool agreement with CPG, with $750 million of reserved borrowing capacity. Columbia OpCo, CEG and OpCo GP guarantee CPG’s $1,500.0 million revolving credit facility, $2.75 billion in aggregate principal amount of CPG’s senior unsecured notes, CPG's commercial paper program and 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:
our ability and Columbia OpCo’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
the funds that we or Columbia OpCo have available for operations and cash distributions to unitholders will be reduced by that portion of our and Columbia OpCo’s respective cash flow required to make principal and interest payments on outstanding debt; and
our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our debt and Columbia OpCo’s debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.
Restrictions in our 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:
make distributions if any default or event of default occurs;
make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests;
incur additional indebtedness or guarantee other indebtedness;
grant liens or make certain negative pledges;
make certain loans or investments;
engage in transactions with affiliates;

26

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



transfer, sell or otherwise dispose of all or substantially all of our or Columbia OpCo’s assets; or
enter into a merger, consolidate, liquidate, wind up or dissolve.
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 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 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 CPG, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.
If we seek a credit rating in the future, our credit rating may be adversely affected by our guarantee of CPG debt and the leverage of our general partner or 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 CPG and its respective affiliates because of its ownership interest in and control of us and the strong operational links between 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.
There can be no assurance that we will be able to access the capital markets on acceptable terms.
From time to time, we will need to access the capital markets to obtain equity or long-term or short-term debt financing. Although we believe that the sources of capital currently in place will permit us to finance our near-term operations on acceptable terms and conditions, our access to, and the availability of, financing on acceptable terms and conditions in the future will be impacted by many factors, including, without limitation: (1) our financial performance, (2) the liquidity of the overall capital markets, (3) the terms of our outstanding debt, and (4) the state of the economy. There can be no assurance that we will have access to the capital markets on terms acceptable to us or at all.
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

27

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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:
new projects may fail to be developed;
new projects may not be developed at their announced capacity;
development of new projects may be significantly delayed;
new projects may be built in locations that are not connected to our system; or
new projects may not influence sources of supply on our system.
Similarly, the development of new, or the expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas on our assets. This could reduce the amount of natural gas transported by our pipeline.
We are exposed to counterparty risk. Commitment termination or nonperformance by our vendors, lenders or derivative counterparties could materially reduce our revenue, impair our liquidity, increase our expenses or otherwise negatively impact our results of operations, financial position or cash flows and our ability to pay cash distributions.
We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis, at the prices we expect and as required by contract could result in significant disruptions, costs to our operation or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results and cash flows.
We also rely to a significant degree on the banks that lend to us under our revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk.
Any take-or-pay commitment terminations or substantial increase in the nonperformance by our vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position and cash flows and our ability to pay cash distributions.
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

28

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:
mistaken assumptions about revenues and costs, including synergies;
the inability to successfully integrate the businesses we acquire;
the inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity or debt;
the diversion of management’s attention from other business concerns;
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 operation of its gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of Columbia OpCo’s computer systems, or those of its customers, suppliers or others with whom it does business, could materially disrupt Columbia OpCo’s ability to operate its businesses and could result in a financial loss and possibly do harm to Columbia OpCo’s reputation.
Additionally, Columbia OpCo’s information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach Columbia OpCo’s cyber-defenses. Although Columbia OpCo attempts to maintain adequate defenses to these attacks and works through industry groups and trade associations to identify common threats and assess Columbia OpCo’s countermeasures, a security breach of Columbia OpCo’s information systems could (i) impact the reliability of Columbia OpCo’s transmission and storage systems and potentially negatively impact Columbia OpCo’s compliance with certain mandatory reliability standards, (ii) subject Columbia OpCo to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to Columbia OpCo’s customers or employees or (iii) impact Columbia OpCo’s ability to manage its businesses.
Sustained extreme weather conditions and climate change may negatively impact Columbia OpCo’s operations.
Columbia OpCo conducts its operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather related stress on Columbia OpCo’s infrastructure may reveal weaknesses in its systems not previously known to it or otherwise present various operational challenges across all business segments. Although Columbia OpCo makes every effort to plan for weather related contingencies, adverse weather may affect its ability to conduct operations in a manner that satisfies customer

29

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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 following the Separation. The inability to recruit and retain these employees could adversely affect our business and future operating results. CEG seeks to mitigate some of this risk by training its management on how to attract and select the needed talent and also measures its level of employee engagement annually, developing action plans where necessary to improve CEG’s workplace, but there is no assurance that such mitigation measures will be effective.
Columbia OpCo’s insurance policies do not cover all losses, costs or liabilities that it may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
Columbia OpCo’s assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes certain pollution liabilities. All of the insurance policies relating to Columbia OpCo’s assets and operations are subject to policy limits and deductibles. In addition, the waiting period under the business interruption insurance policies is 30 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 companies 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.
Adverse economic and market conditions or increases in interest rates could reduce net revenue growth, increase costs, decrease future net income and cash flows and impact capital resources and liquidity needs.
While the national economy is experiencing some recovery from the recent downturn, we cannot predict how robust the recovery will be or whether or not it will be sustained.
Continued sluggishness in the economy impacting our operating jurisdictions could adversely impact our ability to grow our customer base and collect revenues from customers, which could reduce net revenue growth and increase operating costs. An increase in the interest rates we pay would adversely affect future net income and cash flows. In addition, we depend on debt to finance our operations, including both working capital and capital expenditures, and would be adversely affected by increases in

30

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



interest rates. As of December 31, 2015, we had $15 million in outstanding indebtedness, all of which will be subject to variable interest rates.
If the current economic recovery remains slow or credit markets again tighten, our ability to raise additional capital or refinance debt at a reasonable cost could be negatively impacted.
Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.
The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and may yield uncertain returns, which fall below our projected rates of return. A decline in the market value of assets may increase the funding requirements of the obligations under the defined benefit pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, which could potentially increase funding requirements. Further, the funding requirements of the obligations related to these benefits plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. Ultimately, significant funding requirements and increased pension expense could negatively impact our results of operations and financial condition.
We have significant goodwill and definite-lived intangible assets. An impairment of goodwill or definite-lived intangible assets could result in a significant charge to earnings.
In accordance with GAAP, we test goodwill for impairment at least annually and review our definite-lived intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill also is tested for impairment when factors, examples of which include reduced cash flow estimates, a sustained decline in unit price or market capitalization below book value, indicate that the carrying value may not be recoverable. We would be required to record a charge in the financial statements during the period in which any impairment of the goodwill or definite-lived intangible assets is determined, negatively impacting the results of operations. A significant charge could impact the capitalization ratio covenant under certain financing agreements. We are subject to a financial covenant under our credit facilities which requires CPG and the MLP to maintain a total quarterly leverage ratio that does not exceed a ratio of 5.00 to 1.00 until December 31, 2017 and 5.00 to 1.00 for any quarterly period thereafter, with some exceptions. Also, CPG and the MLP are required to maintain a consolidated interest coverage ratio of no less than 3.00 to 1.00. As of December 31, 2015, our quarterly leverage ratio was 3.64 to 1.00 and our consolidated interest coverage ratio was 13.3 to 1.00.
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 December 31, 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:
our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement;
neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duties;

31

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. 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;
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;
our general partner controls the enforcement of obligations that it and its affiliates owe to us;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to CEG’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.
In addition, we may compete directly with our sponsor and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.
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

32

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
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 expect 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:
how to allocate business opportunities among us and its affiliates;
whether to exercise its call right;
how to exercise its voting rights with respect to the units it owns;
whether to exercise its registration rights;
whether to elect to reset target distribution levels; and
whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

33

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to us and holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, not in bad faith, meaning that they did not believe that the decision was adverse to the interest of the partnership, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership, or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and
our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:
(1)
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
(2)
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must not be made in bad faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders.
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.

34

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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.
The market price of our common units may fluctuate significantly
The market price of our common units may fluctuate significantly, depending on many factors, some of which may be beyond our control, including:
a shift in our investor base;
our quarterly or annual earnings, or those of other companies in our industry;
actual or anticipated fluctuations in our operating results;
our payment of distributions, if any;
success or failure of our business strategy;
our ability to obtain financing as needed;
changes in accounting standards, policies, guidance, interpretations or principles;
changes in laws and regulations affecting our business;
announcements by us or our competitors of significant acquisitions or dispositions;
the failure of securities analysts to cover our common units;
changes in earnings estimates by securities analysts or our ability to meet our earnings guidance;
the operating and stock price performance of other comparable companies;
future sales of our common units; and
overall market fluctuations and general economic conditions.
Stock markets in general have also experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations could negatively affect the trading price of our common units.

35

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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.
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 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 do 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 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 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 December 31, 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 provides 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

36

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by CEG could reduce the likelihood of it accepting offers made by us relating to assets owned by CEG, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As of December 31, 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 may 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.

37

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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.
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 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.

38

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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.
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.
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.
In addition, the Internal Revenue Service, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.
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

39

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.
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.
Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
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. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. 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 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.

40

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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 U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter. If the IRS were to challenge our proration method, 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 have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or 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.

41

Columbia Pipeline Partners LP
ITEM 1A. RISK FACTORS (continued)



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.

42

Columbia Pipeline Partners LP
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 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.


43


Columbia Pipeline Partners LP



PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our Limited Partner Interests
On February 6, 2015, our common units began trading on the NYSE under the ticker symbol “CPPL." On February 11, 2015, we completed our offering of 53,833,107 common units at a price to the public of $23.00 per unit. Prior to that time, there was no public market for our common units. The following table sets forth the high and low sales prices for our common units, as reported by the NYSE Composite Transactions, during the periods indicated.
 
2015
  
High
 
Low
First Quarter(1)
$
29.00

 
$
25.39

Second Quarter
28.58

 
25.16

Third Quarter
26.05

 
11.24

Fourth Quarter
18.36

 
12.24

(1)Prices are post-IPO.

As of February 10, 2016, the Partnership had five common unitholders of record and 53,834,784 common units outstanding. We have also issued 46,811,398 subordinated units, for which there is no established public trading market. All of our subordinated units and incentive distribution rights are held by CEG. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.
The following table sets forth the quarterly cash distributions declared on our common and subordinated units for the periods indicated.
(in millions, except per unit amounts)
 
 
 
 
Quarter Ended
Record Date
Payment Date
Per Unit Distribution
Total Cash Distribution
March 31, 2015(1)
May 13, 2015
May 20, 2015
$
0.0912

$
9.2

June 30, 2015
August 13, 2015
August 20, 2015
0.1675

16.9

September 30, 2015
November 13, 2015
November 20, 2015
0.1725

17.4

December 31, 2015
February 11, 2016
February 19, 2016
0.1800

18.1

(1) The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.
Cash Distribution Policy
General
Pursuant to our cash distribution policy, within 60 days after the end of each quarter, 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.
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

44

Columbia Pipeline Partners LP
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (continued)

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.
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.

45

Columbia Pipeline Partners LP
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (continued)

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
%
 
0.0
%
First Target Distribution
 
above $0.16750 up to $0.192625
 
100.0
%
 
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.

46

Columbia Pipeline Partners LP
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (continued)

Performance Graph
The following graph reflects the comparative change in the value from the closing of our IPO on February 11, 2015 through December 31, 2015 of $100 invested in CPPL's common units, the Standard & Poor's 500 Stock Index, and the Alerian MLP Index. The amounts included in the table were calculated assuming the reinvestment of distributions, at the time distributions were paid.
 
February 11, 2015
 
December 31, 2015
Columbia Pipeline Partners LP
$
100.00

 
$
64.68

S&P 500 Index
100.00

 
100.68

Alerian MLP Index
100.00

 
69.16

The information in this Form 10-K appearing under the heading "Performance Graph" is being "furnished" pursuant to Item 2.01 (e) of Regulation S-K under the Securities Act and shall not be deemed to be "soliciting material" or "filed" with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01 (e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that the Partnership specifically requests that it be treated as such.

47

Columbia Pipeline Partners LP
ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read in connection with the Consolidated and Combined Financial Statements including the related notes included in Item 8 of this Form 10-K.
For periods prior to the closing of the Partnership's IPO 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 Columbia OpCo on February 11, 2015. The Partnership owns a 15.7% limited partner interest in Columbia OpCo. The selected data covering periods prior to the closing of the IPO 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 measures of Adjusted EBITDA and Partnership Distributable Cash Flow, which we use in our business as important supplemental measures 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 and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. Partnership Distributable Cash Flow is defined as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income. Adjusted EBITDA and Partnership Distributable Cash Flow are not calculated or presented in accordance with GAAP. We explain these measures under “—Non-GAAP Financial Measures” below and reconcile Adjusted EBITDA and Partnership Distributable Cash Flow to their most directly comparable financial measures calculated and presented in accordance with GAAP.
Year Ended December 31, (dollars in millions except per unit
and operating data)
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
Predecessor
 
Predecessor
 
Predecessor
 
Predecessor
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total Operating Revenues
$
1,331.8

 
$
1,346.9

 
$
1,179.4

 
$
1,000.4

 
$
1,005.6

Operating Expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
526.1

 
630.7

 
507.1

 
374.2

 
377.9

Operating and maintenance-affiliated
164.1

 
122.9

 
118.1

 
105.6

 
98.3

Depreciation and amortization
135.0

 
118.6

 
106.9

 
99.3

 
130.0

(Gain) loss on sale of assets and impairment, net
(54.7
)
 
(34.5
)
 
(18.6
)
 
(0.6
)
 
0.1

Property and other taxes
71.2

 
67.1

 
62.2

 
59.2

 
56.6

Total Operating Expenses
841.7

 
904.8

 
775.7

 
637.7

 
662.9

Equity Earnings in Unconsolidated Affiliates
60.2

 
46.6

 
35.9

 
32.2

 
14.6

Operating Income
550.3

 
488.7

 
439.6

 
394.9

 
357.3

Other Income (Deductions)
 
 
 
 
 
 
 
 
 
Interest expense
(1.4
)
 

 

 

 

Interest expense-affiliated
(26.8
)
 
(62.0
)
 
(37.9
)
 
(29.5
)
 
(29.8
)
Other, net
32.0

 
8.8

 
17.6

 
1.5

 
1.2

Income Taxes
23.9

 
166.4

 
152.4

 
136.9

 
125.6

Net Income
530.2

 
$
269.1

 
$
266.9

 
$
230.0

 
$
203.1

Less: Predecessor net income prior to IPO on February 11, 2015
42.7

 
 
 
 
 
 
 
 
Net income subsequent to IPO
487.5

 
 
 
 
 
 
 
 
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
413.5

 
 
 
 
 
 
 
 
Net income attributable to limited partners subsequent to IPO
$
74.0

 
 
 
 
 
 
 
 
Per Unit Data:
 
 
 
 
 
 
 
 
 
Net income attributable to partners' ownership interest subsequent to IPO per limited partner unit (basic and diluted)
 
 
 
 
 
 
 
 
 
Common units
$
0.74

 
 
 
 
 
 
 
 
Subordinated units
0.72

 
 
 
 
 
 
 
 
Weighted average limited partner units outstanding (basic and diluted)
 
 
 
 
 
 
 
 
 
Common units
53.8

 
 
 
 
 
 
 
 
Subordinated units
46.8

 
 
 
 
 
 
 
 

48

Columbia Pipeline Partners LP
ITEM 6. SELECTED FINANCIAL DATA (continued)

Year Ended December 31, (dollars in millions except per unit
and operating data)
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
Predecessor
 
Predecessor
 
Predecessor
 
Predecessor
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Total assets
$
9,162.0

 
$
8,107.5

 
$
7,261.8

 
$
6,623.2

 
$
6,142.6

Net property, plant and equipment
5,970.8

 
4,960.2

 
4,303.4

 
3,741.5

 
3,398.7

Long-term debt-affiliated, excluding amounts due within one year
630.9

 
1,472.8

 
819.8

 
754.7

 
294.7

Total liabilities
1,585.3

 
3,936.2

 
3,361.9

 
2,883.7

 
2,430.6

Total equity and partners' capital
7,576.7

 
4,171.3

 
3,899.9

 
3,739.5

 
3,712.0

Statement of Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash from (used for):
 
 
 
 
 
 
 
 
 
Operating Activities
$
627.7

 
$
568.1

 
$
454.0

 
$
474.9

 
$
435.3

Investing Activities
(1,052.5
)
 
(864.5
)
 
(797.4
)
 
(455.5
)
 
(307.2
)
Financing Activities
503.2

 
296.6

 
343.1

 
(18.8
)
 
(128.1
)
Other Data:
 
 
 
 
 
 
 
 
 
Adjusted EBITDA
$
682.9

 
$
598.5

 
$
542.7

 
$
496.9

 
$
491.5

Adjusted EBITDA attributable to Partnership subsequent to IPO
93.3

 
 
 
 
 
 
 
 
Partnership Distributable Cash Flow
68.7

 
 
 
 
 
 
 
 
Distributions declared per unit(1)
0.61

 
 
 
 
 
 
 
 
Maintenance and other capital expenditures
132.7

 
143.4

 
132.7

 
209.6

 
220.0

Expansion capital expenditures
1,073.4

 
700.5

 
664.8

 
280.0

 
81.5

Operating Data:(2)
 
 
 
 
 
 
 
 
 
Contracted firm capacity (MMDth/d)
14.3

 
13.2

 
12.9

 
13.2

 
13.2

Throughput (MMDth)
2,022.8

 
2,006.1

 
1,997.3

 
2,200.0

 
2,393.7

Natural gas storage capacity (MMDth)
287

 
287

 
287

 
283

 
282

(1) Includes fourth quarter distribution, which was paid in the first quarter of the subsequent year.
(2) Excludes equity investments.
Non-GAAP Financial Measures
We provide below a discussion of certain non-GAAP financial measures that from time to time we provide to investors as additional information in order to supplement our financial statements, which are presented in accordance with GAAP.
Adjusted EBITDA and Partnership Distributable Cash Flow
We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. In addition, to the extent transactions occur that are considered unusual, infrequent or not representative of underlying trends, we will remove the effect of these items from Adjusted EBITDA. Examples of these transactions include impairments. We define Partnership Distributable Cash Flow as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income.
Adjusted EBITDA and Partnership Distributable Cash Flow are non-GAAP supplemental financial measures 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 presentations of Adjusted EBITDA and Partnership Distributable Cash Flow will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Partnership Distributable Cash Flow are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measures of Adjusted EBITDA and Partnership Distributable Cash Flow should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA and Partnership Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA or Partnership Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA or Partnership Distributable Cash Flow

49

Columbia Pipeline Partners LP
ITEM 6. SELECTED FINANCIAL DATA (continued)

may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA or Partnership Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
The following tables present a reconciliation of Adjusted EBITDA and Partnership Distributable Cash Flow to the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
Predecessor
 
Predecessor
 
Predecessor
 
Predecessor
Net Income
$
530.2

 
$
269.1

 
$
266.9

 
$
230.0

 
$
203.1

Add:
 
 
 
 
 
 
 
 
 
Interest expense
1.4

 

 

 

 

Interest expense-affiliated
26.8

 
62.0

 
37.9

 
29.5

 
29.8

Income taxes
23.9

 
166.4

 
152.4

 
136.9

 
125.6

Depreciation and amortization
135.0

 
118.6

 
106.9

 
99.3

 
130.0

Asset impairment(1)
0.6

 

 

 

 

Distributions of earnings received from equity investees(2)
57.2

 
37.8

 
32.1

 
34.9

 
18.8

Less:
 
 
 
 
 
 
 
 
 
Equity earnings in unconsolidated affiliates(2)
60.2

 
46.6

 
35.9

 
32.2

 
14.6

Other, net(3)
32.0

 
8.8

 
17.6

 
1.5

 
1.2

Adjusted EBITDA
$
682.9

 
$
598.5


$
542.7


$
496.9


$
491.5

Less:
 
 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to Predecessor prior to IPO
79.4

 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
510.2

 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to Partnership subsequent to IPO
$
93.3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Cash Flows from Operating Activities
$
627.7

 
$
568.1

 
$
454.0

 
$
474.9

 
$
435.3

Interest expense
1.4

 

 

 

 

Interest expense-affiliated
26.8

 
62.0

 
37.9

 
29.5

 
29.8

Current taxes
13.4

 
27.1

 
(27.5
)
 
92.2

 
48.8

Gain (loss) on sale of assets and impairment, net
54.7

 
34.5

 
18.6

 
0.6

 
(0.1
)
Other adjustments to operating cash flows
(13.3
)
 
(5.7
)
 
(12.5
)
 
0.8

 
(4.0
)
Changes in assets and liabilities
(27.8
)
 
(87.5
)
 
72.2

 
(101.1
)
 
(18.3
)
Adjusted EBITDA
$
682.9

 
$
598.5

 
$
542.7

 
$
496.9

 
$
491.5

Less:
 
 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to Predecessor prior to IPO
79.4

 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
510.2

 
 
 
 
 
 
 
 
Adjusted EBITDA attributable to Partnership subsequent to IPO
$
93.3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA
$
682.9

 
 
 
 
 
 
 
 
Less:
 
 
 
 
 
 
 
 
 
Interest expense(4)
28.2

 
 
 
 
 
 
 
 
Maintenance capital expenditures(5)
133.8

 
 
 
 
 
 
 
 
Separation maintenance capital expenditures(6)
3.5

 
 
 
 
 
 
 
 
Gain on sale of assets(7)
55.3

 
 
 
 
 
 
 
 
Distributable cash flow attributable to Predecessor prior to IPO
67.8

 
 
 
 
 
 
 
 
Distributable cash flow attributable to noncontrolling interest subsequent to IPO
385.4

 
 
 
 
 
 
 
 
Add:
 
 
 
 
 
 
 
 
 
Proceeds from sales of assets(8)
84.1

 
 
 
 
 
 
 
 
Interest income(9)
4.9

 
 
 
 
 
 
 
 
Capital (received) costs related to Separation(10)
(29.2
)
 
 
 
 
 
 
 
 
Partnership Distributable Cash Flow
$
68.7

 
 
 
 
 
 
 
 

50

Columbia Pipeline Partners LP
ITEM 6. SELECTED FINANCIAL DATA (continued)

(1) Asset impairment is an impairment charge that we consider to be unusual and not indicative of underlying trends.
(2) These adjustments result in Adjusted EBITDA only including actual cash received from equity investees.
(3) Refer to Note 19, "Other, Net" in the Notes to Consolidated and Combined Financial Statements for additional information.
(4) Interest expense consists of interest expense and interest expense-affiliated, net of capitalized amounts.
(5) Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
(6) Separation maintenance capital expenditures are capital expenditures related to the Separation.
(7) Gain on sale of assets consists primarily of gains on conveyances of mineral rights positions.
(8) Proceeds from sales of assets includes $32.7 million cash received for asset transfers made under common control with CEG related to the Separation.
(9) Interest income is primarily composed of income earned on CPPL's lendings to the NiSource Finance money pool prior to the Separation and the CPG money pool subsequent to the Separation.
(10) Capital (received) costs related to Separation are capital expenditures related to the Separation, offset by $32.7 million cash received for asset transfers made under common control with CEG related to the Separation, which is included in proceeds from sales of assets.

51

Columbia Pipeline Partners LP
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. We closed our IPO on February 11, 2015 of 53,833,107 common units. Please see Note 2, "Initial Public Offering" in the Notes to Consolidated and Combined Financial Statements for further discussion. Prior to July 1, 2015, CPG was a wholly owned subsidiary of NiSource. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource ("the Separation"). Our parent company, CEG, was contributed to CPG prior to the Separation. 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 and our 15.7% limited partner interest, we control all of Columbia OpCo’s assets and operations. As a result of this control and the 15.7% limited partner interest, we consolidate Columbia OpCo and CEG's retained interest of 84.3% is recorded as a noncontrolling interest in our consolidated financial statements.
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, 2015, 94.6% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2015, these contracts had a weighted average remaining contract life of 4.8 years.
We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities. Additionally, we expect to increase our ownership interest in Columbia OpCo over time pursuant to our preemptive right to purchase additional limited 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. 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 11,272 miles of natural gas transmission pipeline, 89 compressor stations with 674,905 horsepower of installed capacity and approximately 3,432 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.
Columbia Gulf. Columbia OpCo owns 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with 3,341 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.
Millennium Pipeline. Columbia OpCo owns a 47.5% ownership interest in Millennium Pipeline, which transports an average of 1.1 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.

52

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Hardy Storage. Columbia OpCo owns a 49% ownership interest in Hardy Storage, 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. Columbia OpCo owns 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 123 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. Columbia OpCo owns a 47.5% ownership interest in Pennant, which owns approximately 49 miles of natural gas gathering pipeline infrastructure, a gas processing facility and a 36 mile NGL pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.
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 three 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, which provides ancillary communication services to us and third parties.
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 (defined by the EIA as natural gas produced from shale formations, tight gas and coal beds) such as natural gas shale plays particularly in the Marcellus and Utica shale regions. To illustrate, the EIA reported dry gas production for the month of December 2008, at 1,744,458 million cubic feet. That same statistic increased to 2,302,546 million cubic feet in October 2015. 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 $2.36/MMBtu as of December 31, 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.
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 areas where the economics of natural gas production are less favorable. Despite these reductions, we believe that increased drilling efficiencies and the backlog of drilled but uncompleted wells will likely lead to flat to slightly increasing year-over-year production growth levels out of the Marcellus and Utica regions. Additionally, we believe our assets are well positioned to take advantage of the targeted drilling areas.
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, exportation to Mexico, 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 2014, approximately 38% of the electricity in the U.S. was generated by coal-fired power plants. In addition, the

53

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

EIA’s 2015 Annual Energy Outlook projects that annual domestic consumption of natural gas will increase by approximately 13.4% from 26.1 quadrillion Btu in 2012 to 29.6 quadrillion Btu in 2035.
Commercial Growth and Expansion. 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. Please read “Business and Properties-Current System Expansion Opportunities” for more information on projects we have recently completed or we are currently undertaking.
Our Customers. Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. Our customers use our transportation services for a variety of reasons:
LDCs, municipal utilities, and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. These customers will typically enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract;
Producers of natural gas and LNG exporters require the ability to deliver their product to market and typically enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity; and
Marketers use our transportation services to capitalize on natural gas price volatility over time or between markets.
Impact of New Supply Basins and End-Use Markets. The Columbia Gulf pipeline system was originally constructed for the primary purpose of moving natural gas produced on the Gulf Coast north through Columbia Gas Transmission to midwestern and mid-Atlantic end-use markets. Increases in production in the Marcellus and Utica regions have resulted in a shift of production supply to Northeast markets, displacing the need for production in the Gulf Coast and other Western supply sources. In the past several years, access to new supply and access to new markets have been added to the system through new interconnections and other system modifications. For example, we are currently implementing projects that will make much of the system bi-directional, increasing the flexibility of how we operate this system. As a result of the development of laterals, interconnects, and bi-directional capability, we now have access to multiple strategic natural gas supply sources, including supplies on the Gulf Coast, basins in North Texas (Barnett Shale), East Texas, North Louisiana, the Marcellus and Utica regions, and the Appalachian Basin. Similarly, through interconnections with major interstate and intrastate pipelines, we also access large and growing markets in the northeast, midwest, mid-Atlantic and southeast U.S., and serve industrial, commercial, electric generation and residential customers in various states within our footprint.
Increasing Competition. Our pipeline systems compete primarily with other interstate and intrastate pipelines. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, at least in particular supply or market areas where we serve, and the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term basis, our revenues are not significantly affected by variation in customers’ actual usage resulting from increased competition during the near term. Our ability to remarket the capacity as our contracts expire may be impacted by increased competition.
Regulatory Compliance. Regulation of natural gas transportation by the FERC and other federal and state regulatory agencies, including DOT has a significant impact on our business. For example, the 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 recovered a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these specific costs ceased on January 31, 2015. As of December 31, 2015, Columbia Gas Transmission has remaining liabilities of $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.

54

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

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.

A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015.

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. The recoveries and costs are both reflected in operating expenses.
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 and Partnership Distributable Cash Flow.
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.
We manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our contracts mature at various times and in various amounts of capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. We attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. As of December 31, 2015, our firm revenue contracts had a weighted average remaining contract life of 4.8 years.
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

55

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

capacity. The FERC-regulated transportation and storage operators are obligated to provide firm services only if a shipper is willing to pay the FERC-approved tariff rate.
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, 2015, approximately 94.6% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 3.9% of the transportation and storage revenues were derived from usage fees under firm contracts compared to 94.1% and 4.0%, respectively, for the year ended December 31, 2014.
Interruptible transportation and storage service is typically less than a year and is generally used by customers that either do not need firm service, have been unable to contract for firm service or require transportation volumes in excess of their contracted firm service. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. The FERC-regulated transportation and storage operators are obligated to provide interruptible services only if a shipper is willing to pay the FERC-approved tariff rate. We believe that our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transportation and storage services is our natural gas ‘‘park and loan’’ services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a 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, 2015 and 2014, approximately 1.5% and 1.9%, respectively, of the transportation and storage revenues were derived from interruptible contracts.
Gathering and Processing. Our long-term, fee-based agreements provide for a fixed fee for one or more of the following midstream natural gas services: natural gas gathering, treating, conditioning, processing, compression and liquids handling. Under these agreements, which contain minimum volume commitment features, we are paid a fixed fee based on the volume of the natural gas that we gather and process. Under these agreements, our customers commit to ship a minimum annual volume of natural gas on our gathering system, or, in lieu of shipping such volumes, to pay us periodically as if that minimum amount had been shipped. If capacity is available on the pipeline or at the processing plant, a customer may exceed its minimum volume amounts and pay a fixed fee on the additional volumes. We also provide interruptible gathering and transportation service on our gathering pipelines to optimize our revenues on those systems.
Other Assets. We own the production rights in association with 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 an up to 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 CPGSC, 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.

56

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Adjusted EBITDA and Partnership Distributable Cash Flow. We evaluate our business on the basis of Adjusted EBITDA and Partnership Distributable Cash Flow. Adjusted EBITDA and Partnership Distributable Cash Flow are used as supplemental financial measures 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; and
the operating performance and return on invested capital as compared to those of other publicly 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 and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. Partnership Distributable Cash Flow is defined as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income.
Adjusted EBITDA and Partnership Distributable Cash Flow are not calculated or presented in accordance with GAAP. Adjusted EBITDA and Partnership Distributable Cash Flow should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA and Partnership Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA or Partnership Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA or Partnership Distributable Cash Flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA or Partnership Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and Partnership Distributable Cash Flow to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Financial Data—Non-GAAP Financial Measures.”
Items Affecting Comparability of our Financial Results
The historical financial results discussed below may not be comparable to our future financial results for the following reasons:
For periods prior to the closing of the IPO on February 11, 2015, the financial statements included in this Form 10-K were derived from the financial statements and accounting records of the Predecessor. The 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, CPGSC 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 consolidated financial statements subsequent to the IPO on February 11, 2015 include Columbia OpCo as a consolidated subsidiary, and CEG’s 84.3% interest is reflected as a noncontrolling interest.
We incur incremental annual general and administrative expenses as a result of operating as a publicly traded partnership, which expenses are not reflected in the Predecessor’s financial results for periods prior to our IPO.
Upon the closing of the IPO, 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 CPG and the related interest expense is no longer being incurred.
We are a limited partnership treated as a partnership for U.S. federal income tax purposes and, therefore, are not liable for entity-level federal income taxes. We are subject to state and local income taxes in certain jurisdictions. The

57

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Predecessor’s tax expense was determined on a separate return basis. Accordingly, we expect our tax expense to be significantly reduced subsequent to the IPO as compared to that of the Predecessor.
We have entered into a $500.0 million revolving credit facility. We will incur interest expense at customary short-term interest rates. As of December 31, 2015, we had $15.0 million in outstanding borrowings and issued no letters of credit under the revolving credit facility.
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. Results of operations for the year ending December 31, 2015 and thereafter will benefit from increased revenues associated with the expansion projects identified under “Business and Properties-Current System Expansion Opportunities” above. These projects have provided our customers with increased access to new sources of supply while extending their market reach. We are also continuing to pursue expansion across our footprint that will allow for the transport of constrained natural gas production in the Marcellus and Utica producing regions to areas of demand and/or to locations for conversion to LNGs for exportation off the continent. We expect that completion of these projects will increase utilization along our pipeline system. 
Growth Opportunities. We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include the growth projects listed herein. 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 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 1.61% per year, from 25.57 trillion Btu in 2014 to 33.01 trillion Btu in 2030, while growth in U.S. natural gas demand is only estimated to grow by approximately 0.2% per year, from 27.12 trillion Btu in 2014 to 28.08 trillion Btu in 2030. The net difference between supply and demand is expected, largely, to be exported out of the country through pipeline to Mexico or off the continent by conversion to LNG. The EIA forecasts that the U.S. will transition from a net importer of gas in 2014 of 1.14 Tcf to a net exporter of gas in 2030 of 4.81 Tcf of which net exports of LNG will be 3.29 Tcf. 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 position to capitalize on the LNG export market.

58

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Results of Operations
The following schedule presents the Partnership's and Predecessor's historical consolidated and combined key operating and financial metrics.
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Operating Revenues
 
 
 
 
 
Transportation revenues
$
1,052.2

 
$
990.9

 
$
850.9

Transportation revenues-affiliated
47.1

 
95.8

 
94.3

Storage revenues
171.4

 
144.0

 
142.8

Storage revenues-affiliated
26.2

 
53.2

 
53.6

Other revenues
34.9

 
63.0

 
37.8

Total Operating Revenues
1,331.8

 
1,346.9

 
1,179.4

Operating Expenses
 
 
 
 
 
Operation and maintenance
526.1

 
630.7

 
507.1

Operating and maintenance-affiliated
164.1

 
122.9

 
118.1

Depreciation and amortization
135.0

 
118.6

 
106.9

Gain on sale of assets and impairment, net
(54.7
)
 
(34.5
)
 
(18.6
)
Property and other taxes
71.2

 
67.1

 
62.2

Total Operating Expenses
841.7

 
904.8

 
775.7

Equity Earnings in Unconsolidated Affiliates
60.2

 
46.6

 
35.9

Operating Income
550.3

 
488.7

 
439.6

Other Income (Deductions)
 
 
 
 
 
Interest expense
(1.4
)
 

 

Interest expense-affiliated
(26.8
)
 
(62.0
)
 
(37.9
)
Other, net
32.0

 
8.8

 
17.6

Total Other Income (Deductions), net
3.8

 
(53.2
)
 
(20.3
)
Income before Income Taxes
554.1

 
435.5

 
419.3

Income Taxes
23.9

 
166.4

 
152.4

Net Income
530.2

 
$
269.1

 
$
266.9

Less: Predecessor net income prior to IPO on February 11, 2015
42.7

 
 
 
 
Net income subsequent to IPO
487.5

 
 
 
 
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
413.5

 
 
 
 
Net income attributable to limited partners subsequent to IPO
$
74.0

 
 
 
 
Throughput (MMDth)
 
 
 
 
 
Columbia Gas Transmission
1,460.1

 
1,379.4

 
1,354.3

Columbia Gulf
562.7

 
626.7

 
643.0

Total
2,022.8

 
2,006.1

 
1,997.3


59

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Operating Revenues. Operating revenues were $1,331.8 million for 2015, a decrease of $15.1 million from the same period in 2014. The decrease in operating revenues was due primarily to a decrease of $112.4 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in operating expenses, decreased mineral rights royalty revenue of $17.6 million, lower condensate revenues of $4.5 million, decreased revenue from the settlement of gas imbalances of $4.0 million, and lower commodity revenue of $2.5 million. These decreases were partially offset by increased demand revenue of $128.0 million primarily from the CCRM, the West Side Expansion growth project and other new contracts. Additionally, there were higher shorter term transportation services of $3.5 million.
Operating Expenses. Operating expenses were $841.7 million for 2015, a decrease of $63.1 million from the same period in 2014. The decrease in operating expenses was primarily due to $112.4 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and increased gains on the conveyances of mineral interests of $17.8 million. These variances were partially offset by higher employee and administrative expenses of $25.0 million due to higher employee costs, increased depreciation of $16.4 million primarily due to increased capital expenditures related to projects placed in service, increased outside service costs of $13.4 million, and increased property and other taxes of $4.1 million.
Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $60.2 million in 2015, an increase of $13.6 million compared to the same period in 2014. Equity earnings increased primarily due to the Pennant joint venture going fully in-service and new compression assets being placed into service at Millennium Pipeline.
Other Income (Deductions). Other Income (Deductions) in 2015 increased income by $3.8 million compared to a reduction in income of $53.2 million in 2014. The variance was primarily due to a decrease of $28.4 million in interest expense due to the repayment of long-term debt, an increase of $17.3 million in the equity portion of AFUDC, lower expense of $6.7 million in the debt portion of AFUDC, and increased interest income of $5.5 million.
Income Taxes. The effective income tax rates were 4.3% and 38.2% in 2015 and 2014, respectively. The change in the overall effective tax rates between 2015 and 2014 was primarily due to post-IPO income that is not subject to income tax at the partnership level, as well as the effects of tax credits, state income taxes, utility rate making and other permanent book-to-tax differences.
Throughput. Throughput totaled 2,022.8 MMDth for 2015, compared to 2,006.1 MMDth for the same period in 2014. The increase of 16.7 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.
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 are offset in operating expenses, 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.
Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $46.6 million in 2014, an increase of $10.7 million compared to the same period in 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,

60

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

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 AFUDC.
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 higher AFUDC Equity and consolidated state income taxes.
Throughput. Throughput for the Predecessor totaled 2,006.1 MMDth for 2014, compared to 1,997.3 MMDth for the same period in 2013. The increase of 8.8 million is primarily due to colder weather experienced during early 2014 throughout much of the Partnership's system.
Liquidity and Capital Resources
Our principal liquidity requirements are to finance our operations, fund capital expenditures and acquire 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. Prior to our IPO, 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 were swept into a NiSource corporate account. Therefore, our historical financial statements reflect little or no cash balances.
In connection with our IPO, we 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. In connection with our IPO, CEG assumed the liability for $1,217.3 million of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and NiSource Finance novated the $1,217.3 million of intercompany debt from the subsidiaries to CEG.
Subsequent to our IPO, our sources of liquidity include:
cash generated from our operations;
our $500.0 revolving credit facility;
cash distributions received from Columbia OpCo;
issuances of additional partnership units;
debt offerings;
$750.0 million of reserved borrowing capacity under an intercompany money pool with CPG, 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.

Cash Flow. Net cash from operating activities, net cash used for investing activities and net cash from financing activities for the years ended December 31, 2015, 2014 and 2013, were as follows:
(in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Net cash from operating activities
$
627.7

 
$
568.1

 
454.0

Net cash used for investing activities
(1,052.5
)
 
(864.5
)
 
(797.4
)
Net cash from financing activities
503.2

 
296.6

 
343.1


61

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Operating Activities
Net cash from operating activities for the year ended December 31, 2015 was $627.7 million, an increase of $59.6 million from December 31, 2014. The increase in net cash from operating activities was primarily due to a decrease in income tax amounts subsequent to the IPO as we are not subject to income tax at the partnership level, offset by a customer deposit related to growth projects received in the prior year and higher distribution of earnings from equity investees and other changes in working capital.
Net cash from operating activities for the year ended December 31, 2014 was $568.1 million, an increase of $114.1 million from December 31, 2014. 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.
Pension and Other Postretirement Plan Funding. We expect to make contributions of approximately $0.1 million to our pension plans and approximately $0.9 million to our postretirement medical and life plans in 2016. For the year ended December 31, 2015, we contributed $16.5 million to our pension plans and $11.3 million to our other postretirement medical and life plans.
Investing Activities

The table below reflects actual maintenance and expansion capital expenditures and other investing activities for years ended December 31, 2015, 2014 and 2013 and estimates for 2016.
(in millions)
2016E
 
2015
 
2014
 
2013
 
 
 
 
 
Predecessor
 
Predecessor
Expansion - modernization, system growth and equity investments
$
1,446.1

 
$
1,073.4

 
$
700.5

 
$
664.8

Maintenance and other
139.3

 
132.7

 
143.4

 
132.7

Separation

 
3.5

 

 

Total(1)
$
1,585.4

 
$
1,209.6

 
$
843.9

 
$
797.5

(1) The difference between total capital expenditures in this table and the capital expenditures line item on our statement of cash flows primarily consists of (i) contributions to equity investees, (ii) the non-cash change in capital expenditures included in current liabilities, (iii) the non-cash change in working interest payable and (iv) non-cash AFUDC equity.
Capital expenditures for the year ended December 31, 2015 were $1,209.6 million, compared to $843.9 million for the comparable period in 2014. This increased spending is mainly due to higher spending on various growth projects primarily in the Marcellus and Utica Shale areas and for expenditures under the modernization program. Capital expenditures in 2014 were $46.4 million higher compared to 2013 due to system growth in the Marcellus and Utica shale areas. We project 2016 capital expenditures to be approximately $1.6 billion.
Contributions to equity investees were $1.4 million for the year ended December 31, 2015, a decrease of $67.8 million from a year ago. The contributions in 2015 were made to Millennium Pipeline. During the year ended December 31, 2014, the Predecessor contributed $66.6 million and $2.6 million to Pennant and Millennium Pipeline, respectively. Contributions to equity investees in 2014 were $56.3 million lower compared to 2013. During the year ended December 31, 2013, the Predecessor contributed $108.9 million and $16.6 million to Pennant and Millennium Pipeline, respectively. Distributions received from equity investees increased $16.0 million during the year ended December 31, 2015, primarily due to an additional member joining the Pennant joint venture.
Proceeds from disposition of assets increased $74.8 million during the year ended December 31, 2015, primarily due to increased proceeds received on conveyances of mineral rights positions and proceeds received from asset transfers related to the Separation.
Financing Activities
Net cash from financing activities for the year ended December 31, 2015 was $503.2 million, an increase of $206.6 million compared to the year ended December 31, 2014. The increase in net cash from financing activities was primarily due to net proceeds of the IPO of $1,168.4 million offset by the distribution of $687.3 million to CEG, including a $500.0 million return of preformation capital expenditures. Refer to Note 2, “Initial Public Offering,” in the Notes to Consolidated and Combined Financial Statements for more information.
Net cash from financing activities for the year ended December 31, 2014 was $296.6 million, a decrease of $46.5 million compared to the year ended December 31, 2013. The decrease in net cash from financing activities was due to a decrease in short-term

62

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

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.
Intercompany Credit Agreement Amendment. On January 31, 2016, we amended our intercompany credit agreement with CPG to extend the maturity date of the note originating on December 9, 2013 from December 31, 2016 to December 31, 2020. The outstanding borrowings bear interest at a fixed rate of 4.70%.
Columbia Pipeline Partners LP Credit Agreement. On December 5, 2014, we entered into a $500.0 million senior revolving credit facility, of which $50.0 million in letters of credit is available. The revolving credit facility became effective at the closing of our IPO, with a termination date of February 11, 2020. 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. The loans thereunder bear interest at our option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 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 1.000 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. 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 CPG.
The revolving indebtedness under the credit facility ranks equally with all our outstanding unsecured and unsubordinated debt. CPG, CEG, OpCo GP and Columbia OpCo each fully guarantee the credit facility.
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. The restricted payment provision does not prohibit us or any of our restricted subsidiaries from making distributions in accordance with our respective organizational documents unless there has been an event of default (as defined in our revolving credit agreement), and neither us nor any of our restricted subsidiaries has any restrictions on our ability to make distributions under our organizational documents. In particular, in accordance with our partnership agreement, the general partner has adopted a policy that we will make quarterly cash distributions in amounts equal to at least the minimum quarterly distribution of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. 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 $50.0 million.
The revolving credit facility also contains certain financial covenants that will require us to maintain 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.
A breach 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 us or any guarantor.
As of December 31, 2015, we were in compliance with these covenants. As of December 31, 2015, we had $15.0 million in outstanding borrowings and issued no letters of credit under the revolving credit facility.
Columbia OpCo Money Pool Agreement and CPG Credit Agreement. In connection with the closing of our IPO, Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement, initially with NiSource Finance, with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement is now with CPG. The money pool is available for Columbia OpCo's general partnership purposes, including capital expenditures and working capital.

63

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

In furtherance of the money pool arrangement, CPG has entered into a $1,500.0 million senior revolving credit facility of which $750.0 million will be utilized as credit support for Columbia OpCo and its subsidiaries in connection with the money pool arrangement. The remaining $750.0 million will be available for CPG's general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG's $1,000.0 million commercial paper program. The revolving credit facility became effective as of the Separation with a termination date of July 2, 2020.
Obligations under the CPG revolving credit facility are unsecured. 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 0.500 percent, (b) the reference prime rate of JPMorgan Chase Bank, N.A., or (c) the Eurodollar rate which is based on the LIBOR, plus 1.000 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 did not become effective until the completion of the Separation. 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. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in CPG's revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its 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 $50.0 million.
CPG’s revolving credit facility also contains certain financial covenants that will require CPG to maintain 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.
A breach 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.
As of December 31, 2015, CPG was in compliance with these covenants. As of December 31, 2015, CPG had no borrowings outstanding and had $18.1 million in letters of credit under the revolving credit facility.
CPG Commercial Paper Program. On October 5, 2015, CPG established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the "Securities Act"). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. OpCo GP and Columbia OpCo, together with CEG, have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

64

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Contractual Obligations. The Partnership has certain contractual obligations requiring payments at specified periods. The obligations include short-term borrowings, long-term debt-affiliated, operating lease obligations and service obligations for pipeline service agreements. The total contractual obligations in existence at December 31, 2015 and their maturities were:
(in millions)
Total
2016
2017
2018
2019
2020
After
Short-term borrowings
$
15.0

$
15.0

$

$

$

$

$

Long-term debt-affiliated
630.9





630.9


Interest payments on long-term debt-affiliated
148.6

29.8

29.7

29.7

29.7

29.7


Pipeline transportation capacity arrangements
259.4

51.5

49.5

42.0

25.4

24.2

66.8

Operating leases(1)
46.6

4.5

5.9

5.5

4.8

4.7

21.2

Total contractual obligations
$
1,100.5

$
100.8

$
85.1

$
77.2

$
59.9

$
689.5

$
88.0

(1) Operating lease expense was $18.5 million in 2015, $14.9 million in 2014 and $13.4 million in 2013, 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.
We have third-party transportation agreements that provide for transportation and storage services. These agreements, which have expiration dates ranging from 2016 to 2025, require us to pay fixed monthly charges and allow us to use third-party transportation as operationally needed. Most of these costs are eligible to be collected through a FERC-approved regulatory tracker from our shippers.
Off Balance Sheet Arrangements
We do not have any off balance sheet arrangements.

65

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Other Information
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 the Partnership’s results of operations and Consolidated and Combined Balance Sheets.
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 Consolidated and 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 Consolidated and Combined Balance Sheets were $139.1 million and $310.9 million at December 31, 2015, and $158.0 million and $295.6 million at December 31, 2014, respectively. For additional information, refer to Note 12, “Regulatory Matters,” in the Notes to Consolidated and Combined Financial Statements.
In the event that regulation significantly changes the opportunity for us to recover our 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 transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. 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, 2015. Regulatory assets of $7.2 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 7 years.
Pensions and Postretirement Benefits. CPG has defined benefit plans for both pensions and other postretirement benefits that cover employees of subsidiaries of Columbia OpCo. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of CPG’s pensions and other postretirement benefits, please see Note 15, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated and 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 is a component and has been determined to be a reporting unit. Our goodwill assets at December 31, 2015 and 2014 were $1,975.5 million pertaining to NiSource's acquisition of CEG 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 2014 and 2015, 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 unit in its baseline May 1, 2012 test. The results of this assessment indicated that it is not more likely than not that its reporting unit fair value is less than the reporting unit carrying value and no impairment is necessary.
Although there was no goodwill asset impairment as of May 1, 2015, 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. The Partnership reviewed the market capitalization method due to the recent decline in Partnership's unit price. Following this review, the Partnership determined there were no impairment triggers identified subsequent to May 1, 2015.

66

Columbia Pipeline Partners LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Please see Notes 1-I and 10, “Goodwill” in the Notes to Consolidated and Combined Financial Statements for further discussion.
Revenue Recognition. Revenue is recognized as services are performed. For regulated entities, 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.
Storage capacity revenues 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 $26.5 million, $43.8 million and $21.2 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in “Other revenues” on the Statements of Consolidated and Combined Operations.
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 Partnership 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 amounted to $52.3 million, $34.5 million and $7.3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in “Gain on sale of assets and impairment, net” on the Statements of Consolidated and Combined Operations.
Recently Issued Accounting Pronouncements

Refer to Note 3, "Recent Accounting Pronouncements," in the Notes to Consolidated and Combined Financial Statements.


67

Columbia Pipeline Partners LP
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, our 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 our intercompany term loan and our revolving credit facility. We entered into a variable interest term loan with NiSource Finance which carries an interest rate of prime plus 150 basis points. The loan was transferred from NiSource Finance to CPG in May 2015. As of December 31, 2015 and 2014, the outstanding balance on this term loan was $630.9 million and $834.0 million, respectively. An increase or decrease in interest rates of 100 basis points (1%) would have resulted in increased or decreased annual interest expense of $6.3 million and $8.3 million for the years ended December 31, 2015 and 2014, respectively. Our revolving credit facility has interest rates that are indexed to short-term market interest rates. Based upon average borrowings, an increase or decrease in interest rates of 100 basis points (1%) would have resulted in increased or decreased interest expense of $0.1 million for the year ended December 31, 2015. Our revolving credit facility did not become effective until the closing of our IPO. As a result, there is no effect on the year ended December 31, 2014. 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 CPG’s Corporate Credit Risk Policy. In addition, CPG’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 CPG’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.

68

Columbia Pipeline Partners LP
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

69

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Columbia Pipeline Partners LP
Houston, Texas

We have audited the accompanying consolidated and combined balance sheets of Columbia Pipeline Partners LP and subsidiaries (the “Partnership”) as of December 31, 2015 and 2014, and the related statements of consolidated and combined operations, comprehensive income, cash flows, and equity and partners’ capital for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated and combined financial statements present fairly, in all material respects, the financial position of the Columbia Pipeline Partners LP as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated and combined financial statements, on February 11, 2015 the Partnership completed the initial public offering of limited partner interests for net proceeds of $1,168.4 million.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2016 expressed an unqualified opinion on the Partnership’s internal control over financial reporting.



/s/ DELOITTE & TOUCHE LLP
Columbus, Ohio
February 18, 2016

70

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Columbia Pipeline Partners LP
Houston, Texas

We have audited the internal control over financial reporting of Columbia Pipeline Partners LP and subsidiaries (the "Partnership") as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015, of the Partnership and our report dated February 18, 2016 expressed an unqualified opinion on those financial statements and included an explanatory paragraph relating to the Partnership’s February 11, 2015 initial public offering of limited partner interests.



/s/ DELOITTE & TOUCHE LLP
Columbus, Ohio                                             
February 18, 2016



71

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
CONSOLIDATED AND COMBINED BALANCE SHEETS

(in millions)
December 31, 2015
 
December 31, 2014
 
 
 
Predecessor
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
78.9

 
$
0.5

Accounts receivable (less reserve of $0.3 and $0.3, respectively)
145.9

 
149.3

Accounts receivable-affiliated
149.4

 
153.8

Materials and supplies, at average cost
32.8

 
24.9

Exchange gas receivable
18.8

 
34.8

Deferred property taxes
52.0

 
48.9

Deferred income taxes

 
24.6

Prepayments and other
33.8

 
20.9

Total Current Assets
511.6

 
457.7

Investments
 
 
 
Unconsolidated affiliates
437.1

 
444.3

Other investments
1.8

 
6.2

Total Investments
438.9

 
450.5

Property, Plant and Equipment
 
 
 
Property, plant and equipment
8,930.9

 
7,931.6

Accumulated depreciation and amortization
(2,960.1
)
 
(2,971.4
)
Net Property, Plant and Equipment
5,970.8

 
4,960.2

Other Noncurrent Assets
 
 
 
Regulatory assets
134.1

 
151.9

Goodwill
1,975.5

 
1,975.5

Postretirement and postemployment benefits assets
120.5

 
102.7

Deferred charges and other
10.6

 
9.0

Total Other Noncurrent Assets
2,240.7

 
2,239.1

Total Assets
$
9,162.0

 
$
8,107.5

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.


72

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
CONSOLIDATED AND COMBINED BALANCE SHEETS

(in millions, except unit amounts)
December 31, 2015
 
December 31, 2014
 
 
 
Predecessor
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
 
 
Current portion of long-term debt-affiliated
$

 
$
115.9

Short-term borrowings
15.0

 

Short-term borrowings-affiliated
42.1

 
247.3

Accounts payable
49.9

 
56.1

Accounts payable-affiliated
86.3

 
49.9

Customer deposits
17.8

 
13.4

Taxes accrued
108.2

 
106.9

Exchange gas payable
18.2

 
34.7

Deferred revenue
15.0

 
22.2

Accrued capital expenditures
95.9

 
61.1

Accrued compensation and related costs
26.6

 
31.2

Other accruals
43.8

 
39.0

Total Current Liabilities
518.8

 
777.7

Noncurrent Liabilities
 
 
 
Long-term debt-affiliated
630.9

 
1,472.8

Deferred income taxes
1.0

 
1,239.0

Accrued liability for postretirement and postemployment benefits
36.1

 
44.7

Regulatory liabilities
309.7

 
294.3

Asset retirement obligations
25.3

 
23.2

Other noncurrent liabilities
63.5

 
84.5

Total Noncurrent Liabilities
1,066.5

 
3,158.5

Total Liabilities
1,585.3

 
3,936.2

Commitments and Contingencies (Refer to Note 17)
 
 
 
Equity and Partners' Capital
 
 
 
Net parent investment

 
4,188.0

Common unitholders-public (53,834,784 units issued and outstanding)
958.5

 

Subordinated unitholders-CEG (46,811,398 units issued and outstanding)
304.0

 

Accumulated other comprehensive loss
(4.0
)
 
(16.7
)
Total Columbia Pipeline Partners LP partners' equity and capital
1,258.5

 
4,171.3

Noncontrolling Interest in Columbia OpCo
6,318.2

 

Total Equity and Partners' Capital
7,576.7

 
4,171.3

Total Liabilities and Equity and Partners' Capital
$
9,162.0

 
$
8,107.5

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

73

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

Year Ended December 31, (in millions, except per unit amounts)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Operating Revenues
 
 
 
 
 
Transportation revenues
$
1,052.2

 
$
990.9

 
$
850.9

Transportation revenues-affiliated
47.1

 
95.8

 
94.3

Storage revenues
171.4

 
144.0

 
142.8

Storage revenues-affiliated
26.2

 
53.2

 
53.6

Other revenues
34.9

 
63.0

 
37.8

Total Operating Revenues
1,331.8

 
1,346.9

 
1,179.4

Operating Expenses
 
 
 
 
 
Operation and maintenance
526.1

 
630.7

 
507.1

Operating and maintenance-affiliated
164.1

 
122.9

 
118.1

Depreciation and amortization
135.0

 
118.6

 
106.9

Gain on sale of assets and impairment, net
(54.7
)
 
(34.5
)
 
(18.6
)
Property and other taxes
71.2

 
67.1

 
62.2

Total Operating Expenses
841.7

 
904.8

 
775.7

Equity Earnings in Unconsolidated Affiliates
60.2

 
46.6

 
35.9

Operating Income
550.3

 
488.7

 
439.6

Other Income (Deductions)
 
 
 
 
 
Interest expense
(1.4
)
 

 

Interest expense-affiliated
(26.8
)
 
(62.0
)
 
(37.9
)
Other, net
32.0

 
8.8

 
17.6

Total Other Income (Deductions), net
3.8

 
(53.2
)
 
(20.3
)
Income before Income Taxes
554.1

 
435.5

 
419.3

Income Taxes
23.9

 
166.4

 
152.4

Net Income
530.2

 
$
269.1

 
$
266.9

Less: Predecessor net income prior to IPO on February 11, 2015
42.7

 
 
 
 
Net income subsequent to IPO
487.5

 
 
 
 
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
413.5

 
 
 
 
Net income attributable to controlling interest subsequent to IPO
$
74.0

 
 
 
 
Net income attributable to partners' ownership interest subsequent to IPO per limited partner unit (basic and diluted)
 
 
 
 
 
Common units
$
0.74

 
 
 
 
Subordinated units
0.72

 
 
 
 
Weighted average limited partner units outstanding (basic and diluted)
 
 
 
 
 
Common units
53.8

 
 
 
 
Subordinated units
46.8

 
 
 
 
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

74

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
STATEMENTS OF CONSOLIDATED AND COMBINED COMPREHENSIVE INCOME


Year Ended December 31, (in millions, net of taxes for periods prior to IPO)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Net Income
$
530.2

 
$
269.1

 
$
266.9

Other comprehensive income
 
 
 
 
 
Net unrealized gain on cash flow hedges(1)
1.5

 
1.0

 
1.1

Unrecognized pension and OPEB costs(2)
(0.2
)
 

 

Total other comprehensive income
1.3

 
1.0

 
1.1

Total comprehensive income
531.5

 
$
270.1

 
$
268.0

Total other comprehensive income prior to IPO
0.1

 
 
 
 
Predecessor net income prior to IPO
42.7

 
 
 
 
Total comprehensive income prior to IPO
42.8

 
 
 
 
Total comprehensive income subsequent to IPO
488.7

 
 
 
 
Less: Comprehensive income attributable to noncontrolling interest subsequent to IPO
414.5

 
 
 
 
Comprehensive income attributable to limited partners subsequent to IPO
$
74.2

 
 
 
 
(1) Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.1 million, $0.7 million and $0.6 million tax expense in 2015, 2014 and 2013, respectively.
(2) Unrecognized pension and OPEB costs, net of zero tax expense in 2015, 2014 and 2013, respectively.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.



75

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS


Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Operating Activities
 
 
 
 
 
Net Income
$
530.2

 
$
269.1

 
$
266.9

Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
 
 
 
 
 
Depreciation and amortization
135.0

 
118.6

 
106.9

Deferred income taxes and investment tax credits
10.5

 
139.3

 
179.9

Deferred revenue
4.2

 
1.6

 
(0.5
)
Equity-based compensation expense and profit sharing contribution
5.6

 
6.3

 
2.2

Gain on sale of assets and impairment, net
(54.7
)
 
(34.5
)
 
(18.6
)
Equity earnings in unconsolidated affiliates
(60.2
)
 
(46.6
)
 
(35.9
)
Amortization of debt related costs
0.4

 

 

AFUDC equity
(28.3
)
 
(11.0
)
 
(6.8
)
Distributions of earnings received from equity investees
57.2

 
37.8

 
32.1

Changes in Assets and Liabilities:
 
 
 
 
 
Accounts receivable
(11.0
)
 
(20.3
)
 
2.5

Accounts receivable-affiliated
21.6

 
2.2

 
(7.6
)
Accounts payable
(10.0
)
 
2.8

 
5.5

Accounts payable-affiliated
30.1

 
8.6

 
16.3

Customer deposits
(22.9
)
 
77.5

 
1.3

Taxes accrued
19.5

 
11.8

 
(28.5
)
Exchange gas receivable/payable

 
1.1

 
(0.5
)
Other accruals
10.5

 
0.6

 
0.4

Prepayments and other current assets
(13.5
)
 
(4.4
)
 
21.7

Regulatory assets/liabilities
27.6

 
9.0

 
42.6

Postretirement and postemployment benefits
(5.2
)
 
2.2

 
(113.3
)
Deferred charges and other noncurrent assets
(13.8
)
 
(4.3
)
 
2.5

Other noncurrent liabilities
(5.1
)
 
0.7

 
(15.1
)
Net Cash Flows from Operating Activities
627.7

 
568.1

 
454.0

Investing Activities
 
 
 
 
 
Capital expenditures
(1,106.6
)
 
(747.2
)
 
(674.8
)
Insurance recoveries
2.1

 
11.3

 
6.4

Changes in short-term lendings-affiliated
(24.3
)
 
(61.6
)
 
(10.0
)
Proceeds from disposition of assets
84.1

 
9.3

 
15.4

Contributions to equity investees
(1.4
)
 
(69.2
)
 
(125.5
)
Distributions from equity investees
16.0

 

 

Other investing activities
(22.4
)
 
(7.1
)
 
(8.9
)
Net Cash Flows used for Investing Activities
(1,052.5
)
 
(864.5
)
 
(797.4
)
Financing Activities
 
 
 
 
 
Change in short-term borrowings
15.0

 

 

Change in short-term borrowings-affiliated
(207.2
)
 
(472.3
)
 
391.0

Issuance of long-term debt-affiliated

 
768.9

 
65.1

Payments of long-term debt-affiliated, including current portion
(959.6
)
 

 

Proceeds from issuance of common units, net of offering costs
1,168.4

 

 

Distribution of IPO proceeds to parent
(500.0
)
 

 

Contribution of capital from parent
1,217.3

 

 

Distribution to parent

 

 
(113.0
)
Quarterly distributions to unitholders
(43.4
)
 

 

Distribution to noncontrolling interest in Columbia OpCo
(187.3
)
 

 

Net Cash Flows from Financing Activities
503.2

 
296.6

 
343.1

Change in cash and cash equivalents
78.4

 
0.2

 
(0.3
)
Cash and cash equivalents at beginning of period
0.5

 
0.3

 
0.6

Cash and Cash Equivalents at End of Period
$
78.9

 
$
0.5

 
$
0.3

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

76

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Partners LP
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY AND PARTNERS' CAPITAL

 
Predecessor
 
Partnership
 
 
 
 
(in millions)
Net Parent Investment
 
Common Unitholders
 
Subordinated Unitholders
 
Noncontrolling interest
 
Accumulated
Other
Comprehensive
Loss
 
Total
Balance as of January 1, 2013
$
3,758.3

 
$

 
$

 
$

 
$
(18.8
)
 
$
3,739.5

Net Income
266.9

 

 

 

 

 
266.9

Other comprehensive income, net of tax

 

 

 

 
1.1

 
1.1

Dividends to parent
(113.0
)
 

 

 

 

 
(113.0
)
Net transfers from parent
5.4

 

 

 

 

 
5.4

Balance as of 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 as of December 31, 2014
$
4,188.0

 
$

 
$

 
$

 
$
(16.7
)
 
$
4,171.3

Net income from January 1, 2015 to February 10, 2015
42.7

 

 

 

 

 
42.7

Other comprehensive income, net of tax, from January 1, 2015 through February 10, 2015

 

 

 

 
0.1

 
0.1

Contribution of capital from parent
1,217.3

 

 

 

 

 
1,217.3

Predecessor net tax liabilities not assumed by Columbia OpCo(1)
1,232.5

 

 

 

 
(10.3
)
 
1,222.2

Contribution/Noncontributed Net Parent Investment Adjustments(2)
(7.7
)
 

 

 

 

 
(7.7
)
Balance as of February 11, 2015 (prior to IPO)
$
6,672.8

 
$

 
$

 
$

 
$
(26.9
)
 
$
6,645.9

Allocation of net investment to unitholders
(6,672.8
)
 

 
487.1

 
6,185.7

 

 

Allocation of accumulated other comprehensive loss to noncontrolling interest

 

 

 
(22.7
)
 
22.7

 

Net proceeds from IPO

 
1,168.4

 

 

 

 
1,168.4

Purchase of additional interest in OpCo(3)

 
(227.1
)
 
(197.3
)
 
424.4

 

 

Distributions to the noncontrolling interest in Columbia OpCo

 

 

 
(687.3
)
 

 
(687.3
)
Net income from February 11, 2015 through December 31, 2015

 
39.9

 
34.1

 
413.5

 

 
487.5

Other comprehensive income, net of tax, from February 11, 2015 through December 31, 2015

 

 

 
1.0

 
0.2

 
1.2

Quarterly distributions to unitholders

 
(23.2
)
 
(20.2
)
 

 

 
(43.4
)
Transfers from parent(4)

 
0.5

 
0.3

 
3.6

 

 
4.4

Balance as of December 31, 2015
$

 
$
958.5

 
$
304.0

 
$
6,318.2

 
$
(4.0
)
 
$
7,576.7

(1)Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-IPO, as well as associated regulatory assets and liabilities.
(2)Reflects the removal of amounts related to Crossroads Pipeline Company, CPGSC, Central Kentucky Transmission Company and 1% of the 50% interest in Hardy Storage that were included in the Predecessor but were not contributed to the Partnership, as well as the inclusion of CNS Microwave, which was not part of the Predecessor.
(3)Represents the purchase of an additional 8.4% limited partner interest in Columbia OpCo, recorded at the historical carrying value of Columbia OpCo's net assets after giving effect to the $1,168.4 million equity contribution. This decreases common unitholders and subordinated unitholders equity by the same amount it increases noncontrolling interest because the Partnership's purchase price for its additional 8.4% interest in Columbia OpCo exceeded book value.
(4)As part of the Separation from NiSource, certain assets on Columbia OpCo's subsidiaries' accounts were purchased by CEG at fair value and then sold to NiSource. As Columbia OpCo and CEG are entities under common control, this amount represents the difference between book value and fair value of those assets.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
 


77

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


1.
Nature of Operations and Summary of Significant Accounting Policies

A.       Company Structure and Basis of Presentation.    Columbia Pipeline Partners LP (the "Partnership") was formed in Delaware on December 5, 2007, as a subsidiary of NiSource Inc. ("NiSource"). CEG owns the general partner of the Partnership and all of the Partnership’s subordinated units and incentive distribution rights. On February 11, 2015, NiSource contributed its subsidiary CEG to CPG. Following this contribution, CPG owns and operates, through its subsidiaries, approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of CPG. Prior to July 1, 2015, CPG was a wholly owned subsidiary of NiSource. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource ("the Separation"). As a result of the Separation, CPG became an independent publicly traded company. Columbia Pipeline Partners LP Predecessor (the “Predecessor”) is comprised of NiSource’s Columbia Pipeline Group Operations reportable segment.
The Partnership is engaged in regulated interstate gas transportation and storage services for LDCs, marketers, producers 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 at rates subject to FERC approval.
Concurrent with the completed IPO, refer to Note 2 for a discussion of IPO results, NiSource contributed substantially all of the assets and operations of the Predecessor to Columbia OpCo, a Delaware limited partnership formed by CEG, which, prior to the Separation, was a wholly owned subsidiary of NiSource, and OpCo GP, a wholly owned subsidiary of the Partnership. The contribution is considered to be a reorganization of entities under common control. Subsequent to the IPO, the Partnership owns a 15.7% limited partner interest in Columbia OpCo and CEG owns the remaining 84.3% limited partner interest. MLP GP, a wholly owned subsidiary of CEG, serves as the general partner of the Partnership. OpCo GP serves as the general partner of Columbia OpCo. CPGSC 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. Through ownership of Columbia OpCo’s general partner, the Partnership controls all of Columbia OpCo’s assets and operations. As a result of this control and the 15.7% limited partner interest, the Partnership consolidates Columbia OpCo and CEG's retained interest of 84.3% is recorded as noncontrolling interest in the Partnership's consolidated financial statements.
For periods subsequent to the closing of the IPO, the financial statements included in this annual report are the financial statements and accounting records of the Partnership. For periods prior to the closing of the IPO, the financial statements included in this annual report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows:
The Consolidated and Combined Balance Sheets consist of the consolidated balance sheet of the Partnership as of December 31, 2015 and the combined balance sheet of the Predecessor as of December 31, 2014.
The Statements of Consolidated and Combined Operations consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013.
The Statements of Consolidated and Combined Comprehensive Income consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013.
The Statements of Consolidated and Combined Cash Flows consist of the consolidated cash flows of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined cash flows of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013.
The Statements of Consolidated and Combined Equity and Partners' Capital consist of the consolidated activity of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined activity of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013.

78

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The Partnership’s accompanying Consolidated and Combined Financial Statements have been prepared in accordance with GAAP. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream, CEVCO, CNS Microwave, OpCo GP, Columbia OpCo and the Partnership. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline, and Pennant. All intercompany transactions and balances have been eliminated.
B.    Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
C.    Cash and Cash Equivalents.  Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.
D.    Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is the Partnership'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.    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 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 Consolidated and 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 Partnership to recover its costs in the future, all or a portion of the Partnership’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 Partnership’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of regulatory accounting, the Partnership would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, the Partnership’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 12, "Regulatory Matters," in the Notes to Consolidated and 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 Partnership's rate-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 Partnership's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties.
 
The Partnership 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 ADUFC equity are summarized in the table below:
 
2015
 
2014
 
2013
 
Debt
 
Equity
 
Debt
 
Equity
 
Debt
 
Equity
 
 
 
 
 
Predecessor
 
Predecessor
Columbia Gas Transmission
1.8
%
 
6.3
%
 
0.9
%
 
3.0
%
 
2.5
%
 
3.2
%
Columbia Gulf
2.9
%
 
6.3
%
 
2.1
%
 
9.4
%
 
2.5
%
 
3.2
%
The Partnership 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 utility plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.

79

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 the years ended December 31, 2015, 2014 and 2013. Please see Note 8, "Gain on Sale of Assets," in the Notes to Consolidated and 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 Consolidated and Combined Balance Sheets.
H.    Amortization of Software Costs.    External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. The Partnership amortized $5.8 million in 2015, $4.3 million in 2014 and $5.0 million in 2013 related to software costs. The Partnership’s unamortized software balance was $27.1 million and $18.3 million at December 31, 2015 and 2014, respectively.
I.    Goodwill.    The Partnership 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 CEG acquisition on November 1, 2000. Please see Note 10, "Goodwill," in the Notes to Consolidated and 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 assets 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. The Partnership recognized an impairment loss of $0.6 million for the year ended December 31, 2015 and zero for the years ended December 31, 2014 and 2013.
K.    Revenue Recognition.    Revenue is recorded 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 for 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 Partnership provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided.
Storage capacity revenues 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 Partnership 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 realized. Royalty revenue was $26.5 million, $43.8 million and $21.2 million for the years ended December 31, 2015, 2014 and 2013, respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations.
The Partnership periodically recognizes gains on the conveyance of mineral interest related to 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 Partnership 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 conveyances amounted to $52.3 million, $34.5 million and $7.3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations.
L.    Estimated Rate Refunds.    The Partnership collects revenue 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.
 

80

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

M.    Accounting for Exchange and Balancing Arrangements of Natural Gas.    The Partnership enters into balancing and exchange arrangements of natural gas as part of its operations. The Partnership 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 Partnership’s Consolidated and Combined Balance Sheets, as appropriate.
N.    Income Taxes and Investment Tax Credits.    The Partnership is a limited partnership and is treated as a partnership for U.S. federal income tax purposes and therefore, is not liable for entity-level federal income taxes. The Predecessor's operating results were included in NiSource's consolidated U.S. federal and in consolidated, combined or stand-alone state income tax returns. Amounts presented in the combined financial statements prior to the IPO relate to income taxes that have been determined on a separate tax return basis, and the Predecessor's contribution to NiSource's net operating losses and tax credits have been included in the Predecessor's financial statements.
O.    Environmental Expenditures.    The Partnership 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 reserves for estimated environmental expenditures are recorded on the Consolidated and Combined Balance Sheets in “Other Accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. The Partnership establishes regulatory assets on the Consolidated and Combined Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 17, "Other Commitments and Contingencies" in the Notes to Consolidated and Combined Financial Statements for further discussion.
P.    Accounting for Investments.    The Partnership accounts for its ownership interests in 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 Partnership (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.
The Partnership has a 49% interest in Hardy Storage. The Predecessor had a 50% interest in Hardy Storage. The Partnership and the Predecessor reflect the investment in Hardy Storage as an equity method investment.
Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. During the third quarter of 2015, an additional member, an affiliate of Williams Partners, joined the Pennant joint venture. Williams Partners' initial ownership investment in Pennant is 5.00%, and by funding specified investment amounts for future growth projects, Williams Partners can invest directly in the growth of Pennant. Such funding will potentially increase Williams Partners' ownership in Pennant up to 33.33% over a defined investment period. As a result of the buy-in, Columbia Midstream received $12.7 million in cash and recorded a gain of $2.9 million, and its ownership interest in Pennant decreased from 50.0% to 47.5%. The Partnership accounts for the joint venture under the equity method of accounting.
Q.        Natural Gas and Oil Properties.    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. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. 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.

81

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015 and 2014:
(in millions)
2015
 
2014
Beginning Balance
$
14.9

 
$
1.9

Additions pending the determination of proved reserves
1.3

 
20.1

Reclassifications of proved properties
(14.5
)
 
(7.1
)
Ending Balance
$
1.7

 
$
14.9

As of December 31, 2015, there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to one project initiated in 2013.
2.    Initial Public Offering
On February 6, 2015, the Partnership's common units began trading on the New York Stock Exchange under the ticker symbol "CPPL." On February 11, 2015 the Partnership completed its offering of 53,833,107 common units at a price to the public of $23.00 per unit, including 7,021,709 common units that were issued pursuant to the exercise in full of the underwriters' over-allotment option. The Partnership received net proceeds of $1,168.4 million from the offering. At or prior to the closing of the offering the following transactions occurred:
CEG contributed $1,217.3 million of capital to certain subsidiaries of the Predecessor to repay intercompany debt owed to NiSource Finance. CEG entered into new intercompany debt agreements with NiSource Finance for $1,217.3 million;
CEG contributed substantially all of the subsidiaries in the Predecessor to Columbia OpCo;
CEG assumed responsibility for all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-IPO, as well as associated regulatory assets and liabilities;
CEG contributed a 7.3% limited partner interest in Columbia OpCo in exchange for 46,811,398 subordinated units in the Partnership and all of the Partnership's incentive distribution rights;
the Partnership purchased from Columbia OpCo an additional 8.4% limited partner interest in exchange for $1,168.4 million from the net proceeds of the IPO, net of underwriting discounts, structuring fees and offering expenses of approximately $69.8 million, resulting in the Partnership owning a 15.7% limited partner interest in Columbia OpCo;

The table below summarizes the effects of the changes in the Partnership's ownership interest in Columbia OpCo on the Partnership's equity:
 
Year Ended December 31,
(in millions)
2015
Net income attributable to the Partnership
$
74.0

Decrease in partnership equity for the purchase of an additional 8.4 percent interest in Columbia OpCo
(424.4
)
Change from net income attributable to the Partnership and transfers to noncontrolling interest
$
(350.4
)
Columbia OpCo distributed $500.0 million to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo.
The Partnership entered into an omnibus agreement with CEG and its affiliates (together with a services agreement with CPGSC) at the closing of the IPO that addresses (1) centralized corporate, general and administrative services to be provided by CEG for the Partnership and the reimbursement by the Partnership for the Partnership's portion of these services, (2) the Partnership's right of first offer for CEG's 84.3% interest in Columbia OpCo, (3) the indemnification of the Partnership for certain potential environmental and toxic tort claims losses and expenses associated with the operation of the assets and occurring before the closing date of the IPO and (4) Columbia OpCo's requirement to guarantee future indebtedness that CPG incurs.

82

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

3.
Recent Accounting Pronouncements

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. In August 2015, the FASB issued ASU 2015-15 to clarify the SEC staff's position on these costs in relation to line-of-credit agreements stating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of such arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. The Partnership is required to adopt ASU 2015-03 and ASU 2015-15 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively with early adoption permitted. The Partnership does not anticipate the adoption of ASU 2015-03 and ASU 2015-15 will have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

In May 2014, the FASB issued ASU 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. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2017, including interim periods, and the new standard is to be applied retrospectively with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. The Partnership is currently evaluating the impact the adoption of ASU 2014-09 and ASU 2015-14 will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The Partnership is required to adopt ASU 2015-06 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively, with early adoption permitted. The Partnership does not anticipate the adoption of ASU 2015-06 will have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. The Partnership is required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. The Partnership is currently evaluating the impact the adoption of ASU 2015-02 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate that the impact will be material.
4.
Partners' Equity and Cash Distributions
Common Unit. As described below, the common unitholders have preference over subordinated unitholders on receipt of distributions, including, in certain circumstances, cash distributions upon liquidation, as set out in the Partnership's Second Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement"). The common unitholders have limited rights on matters affecting Partnership's business, limited voting rights and are not entitled to elect the general partner or its directors.
Subordinated Unit. The subordinated unitholders have similar rights as the common unitholders. However, during the subordination period, the subordinated unitholders are not entitled to receive quarterly distributions from operating surplus until the common unitholders have received the minimum quarterly distribution from operating surplus and, among other things, in certain circumstances, are subordinated in the receipt of cash distributions upon liquidation. The subordination period will end on the first business day after the Partnership has earned and paid an aggregate amount of at least the minimum quarterly distribution multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter

83

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

periods ending on or after March 31, 2018 and there are no outstanding arrearages on the Partnership's common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least 150.0% of the minimum quarterly distribution on an annualized basis multiplied by the total number of outstanding common and subordinated units and have earned that amount plus the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2016 and there are no outstanding arrearages on the Partnership's common units.
Incentive Distribution Rights. The Partnership Agreement generally provides that the Partnership will distribute cash each quarter during the subordination period in the following manner: first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.192625, plus any arrearages from prior quarters; second, 85.0% to the holders of common and subordinated units, pro rata, and 15.0% to CEG as the holder of the incentive distribution rights, until each unitholder has received the minimum quarterly distribution of $0.209375; and third, 75.0% to the holders of common and subordinated units, pro rata, and 25.0% to CEG as the holder of the incentive distribution rights, until each unitholder has received a distribution of $0.251250. If cash distributions to the Partnership's unitholders exceed $0.251250 per common unit and subordinated unit in any quarter, the Partnership will distribute 50.0% to the holders of common and subordinated units, pro rata, and 50.0% to CEG as the holder of the incentive distribution rights.
The Partnership has paid or has authorized payment of the following quarterly cash distributions under the Partnership Agreement during 2015:
(in millions, except per unit amounts)
 
 
 
 
Quarter Ended
Record Date
Payment Date
Per Unit Distribution
Total Cash Distribution
March 31, 2015(1)
May 13, 2015
May 20, 2015
$
0.0912

$
9.2

June 30, 2015
August 13, 2015
August 20, 2015
0.1675

16.9

September 30, 2015
November 13, 2015
November 20, 2015
0.1725

17.4

December 31, 2015
February 11, 2016
February 19, 2016
0.1800

18.1

(1) The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.
5.
Net Income Per Limited Partner Unit
The Partnership computes earnings per unit using the two-class method for Master Limited Partnerships. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
The Partnership calculates net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the Partnership Agreement and as further prescribed by ASC 260 under the two-class method.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights holder under the terms of the Partnership Agreement, even though we make distributions on the basis of available cash and not earnings.
Net income per unit applicable to common units and to subordinated units is computed by dividing the respective limited partners’ interest in net income by the weighted-average number of common units and subordinated units outstanding for the period. The classes of participating securities include common units, subordinated units and incentive distribution rights. Basic and diluted net income per unit are the same because the Partnership does not have any potentially dilutive units outstanding for the periods presented.

84

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Pursuant to our cash distribution policy, within 60 days after the end of each quarter, we intend to distribute to the holders of common units 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.
On January 29, 2016, the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period October 1, 2015, through December 31, 2015, of $0.1800 per unit, or $18.1 million in total. This distribution is payable on February 19, 2016, to unit holders of record as of February 11, 2016.

The calculation of net income per unit is as follows:
 
 
Year Ended December 31, 2015                                                                           (in millions, except per unit data)
Limited Partners' Common Units
 
Limited Partners' Subordinated Units
 
Incentive Distribution Rights
 
Total
Net income attributable to partners
 
 
 
 
 
 
 
Distribution
$
32.9

 
$
28.7

 
$

 
$
61.6

Net income in excess of distribution(1)
6.7

 
5.1

 
0.6

 
12.4

Net income attributable to partners
$
39.6

 
$
33.8

 
$
0.6

 
$
74.0

 
 
 
 
 
 
 
 
Weighted-average limited partner units outstanding
 
 
 
 
 
 
 
Basic and diluted
53.8

 
46.8

 
 
 
100.6

Net income attributable to partners' ownership interest subsequent to IPO per limited partner unit
 
 
 
 
 
 
 
Basic and diluted
$
0.74

 
$
0.72

 
 
 
$
0.74

(1) Net income attributable to partners in excess of distribution is for the period subsequent to the IPO.


85

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

6.    Transactions with Affiliates
Prior to CPG's separation from NiSource, the Partnership engaged in transactions with subsidiaries of NiSource which were deemed to be affiliates of the Partnership. The Partnership continues to engage in transactions with subsidiaries of CPG subsequent to the Separation. These affiliate transactions are summarized in the tables below:
Statement of Operations
 
Year Ended December 31,
(in millions)
2015
 
2014
 
2013
 
 
 
Predecessor

 
Predecessor

Transportation revenues
$
47.1

 
$
95.8

 
$
94.3

Storage revenues
26.2

 
53.2

 
53.6

Other revenues
0.2

 
0.3

 
0.3

Operation and maintenance expense
164.1

 
122.9

 
118.1

Interest expense
26.8

 
62.0

 
37.9

Interest income
4.8

 
0.5

 
0.5

Balance Sheet
(in millions)
December 31, 2015
 
December 31, 2014
 
 
 
Predecessor
Accounts receivable
$
149.4

 
$
153.8

Current portion of long-term debt

 
115.9

Short-term borrowings
42.1

 
247.3

Accounts payable
86.3

 
49.9

Long-term debt
630.9

 
1,472.8

Transportation, Storage and Other Revenues. Prior to the Separation, the Partnership provided natural gas transportation, storage and other services to subsidiaries of NiSource, the Partnership's former affiliates. Prior to the IPO, the Predecessor provided similar services to subsidiaries of NiSource.
Operation and Maintenance Expense. The Partnership receives executive, financial, legal, information technology and other administrative and general services from CPGSC. Prior to the IPO, the Predecessor received similar services from NiSource Corporate Services. Expenses incurred as a result of these services consist of employee compensation and benefits, outside services and other expenses. The expenses are 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 Partnership and Predecessor were charged interest for long-term debt of $35.1 million, $61.6 million and $40.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, offset by associated AFUDC of $9.2 million, $2.7 million and $6.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the date of the IPO. Following the Separation, the agreement is now with CPG. The money pool is available for Columbia OpCo and its subsidiaries' general purposes, including capital expenditures and working capital. This intercompany money pool agreement is discussed in connection with Short-term Borrowings below. Prior to the IPO, the subsidiaries of the Predecessor participated in a similar money pool agreement with NiSource Finance. CPGSC administers the current money pool agreement. The cash accounts maintained by the subsidiaries of Columbia OpCo and the Predecessor were, prior to the Separation, 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 subsidiary. Subsequent to the Separation, cash accounts maintained by subsidiaries of Columbia OpCo were swept into a CPG corporate account on a daily basis, creating an affiliated receivable or decreasing an

86

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

affiliated payable, as appropriate, between CPG and the subsidiary. The amount of interest expense and income for short-term borrowings was determined by the net position of each subsidiary in the money pool. The money pool weighted-average interest rate at December 31, 2015 and 2014 was 1.21% and 0.70%, respectively. The interest expense for short-term borrowings charged for the years ended December 31, 2015, 2014 and 2013 was $0.9 million, $3.1 million and $4.1 million, respectively.
Accounts Receivable. The Partnership includes in accounts receivable amounts due from the money pool discussed above of $140.5 million at December 31, 2015 for subsidiaries of Columbia OpCo in a net deposit position. The Predecessor includes in accounts receivable amounts due from the money pool discussed above of $125.0 million at December 31, 2014 for subsidiaries in a net deposit position. Also included in the balance at December 31, 2015 and December 31, 2014 are amounts due from subsidiaries of CPG, subsequent to the Separation, or NiSource, prior to the Separation, of $8.9 million and $28.8 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Statements of Consolidated and Combined Statements of Cash Flows. All other affiliated receivables are included as Operating Activities.
Short-term Borrowings. In connection with the closing of the IPO, the subsidiaries of Columbia OpCo entered into an intercompany money pool agreement with NiSource Finance with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement is now with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. The CPG revolving credit agreement became effective at the completion of the Separation with a termination date of July 2, 2020. Each of CEG, OpCo GP and Columbia OpCo is a guarantor of CPG's revolving credit facility. 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. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance to their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo's partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo's business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At December 31, 2015, neither CPG nor its subsidiaries had any restricted assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to the Partnership. 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 $50.0 million. 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.
The balance of Short-term Borrowings at December 31, 2015 and December 31, 2014 of $42.1 million and $247.3 million, respectively, includes those subsidiaries of Columbia OpCo and includes those 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 Statements of Consolidated and Combined Statements of Cash Flows.
Accounts Payable. The affiliated accounts payable balance primarily includes amounts due for services received from CPGSC, subsequent to the Separation, and NiSource Corporate Services, prior to the Separation, and interest payable to CPG, subsequent to the Separation, and NiSource Finance, prior to the Separation.

87

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Long-term Debt. In May 2015, the Partnership's outstanding intercompany debt transferred from NiSource Finance to CPG. The Partnership’s long-term financing requirements are satisfied through borrowings from CPG. On January 31, 2016, the Partnership amended its intercompany credit agreement with CPG to extend the maturity date of the note originating on December 9, 2013 from December 31, 2016 to December 31, 2020. Details of the long-term debt balance are summarized in the table below:
Origination Date
 
Interest Rate
 
Maturity Date
 
December 31, 2015
 
December 31, 2014
(in millions)
 
 
 
 
 
 
 
Predecessor
November 28, 2005(1)
 
5.41
%
 
November 30, 2015
 
$

 
$
115.9

November 28, 2005
 
5.45
%
 
November 28, 2016
 

 
45.3

November 28, 2005
 
5.92
%
 
November 28, 2025
 

 
133.5

November 28, 2012
 
4.63
%
 
November 28, 2032
 

 
45.0

November 28, 2012
 
4.94
%
 
November 30, 2037
 

 
95.0

December 19, 2012
 
5.16
%
 
December 21, 2037
 

 
55.0

November 28, 2012
 
5.26
%
 
November 28, 2042
 

 
170.0

December 19, 2012
 
5.49
%
 
December 18, 2042
 

 
95.0

December 9, 2013(2)
 
4.70
%
 
December 31, 2020
 
630.9

 
834.0

Total long-term debt, including current portion
 
 
 
 
 
$
630.9

 
$
1,588.7

(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 Sheet as of December 31, 2014.
(2) The Partnership may borrow at any time from the origination date to December 31, 2016 not to exceed $2.6 billion. From January 1, 2017 to December 31, 2020, the Partnership may borrow at any time not to exceed $2.3 billion. As of the January 2016 amendment, the note carries a fixed interest rate of 4.70% for the outstanding borrowings as of December 31, 2015.

Dividends. During the year ended December 31, 2015, Columbia OpCo distributed $687.3 million to CEG, of which $500.0 million was a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. The Predecessor paid no dividends to CEG in the year ended December 31, 2014 and paid $113.0 million to CEG in the year ended December 31, 2013. There were no restrictions on the payment by the Partnership of dividends to CEG.
7.
Short-Term Borrowings
On December 5, 2014, the Partnership entered into a $500.0 million senior revolving credit facility, of which $50.0 million in letters is available. The revolving credit facility became effective at the closing of the IPO with a termination date of February 11, 2020. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls to Columbia OpCo.
Obligations under the revolving credit facility are unsecured. The loans thereunder bear interest at the Partnership's option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 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 1.000 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. 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 CPG.
The revolving indebtedness under the credit facility ranks equally with all of the Partnership's outstanding unsecured and unsubordinated debt. CPG, CEG, OpCo GP and Columbia OpCo each fully guarantee the credit facility.
The revolving credit facility contains various covenants and restrictive provisions which, among other things, limit the Partnership'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. The restricted payment provision does not prohibit the Partnership or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither the Partnership nor any of its restricted

88

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

subsidiaries has any restrictions on its ability to make distributions under its organizational agreements. In particular, in accordance with the partnership agreement, the general partner has adopted a policy that the Partnership will make quarterly cash distributions in amounts equal to at least the minimum quarterly distribution of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. At December 31, 2015, neither the Partnership nor its consolidated subsidiaries had any restricted assets. If the Partnership fails to perform its 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. The revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $50.0 million.
The revolving credit facility also contains certain financial covenants that require the Partnership to maintain 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.
A breach 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 the Partnership or any guarantor.

As of December 31, 2015, the Partnership had $15.0 million of outstanding borrowings and issued no letters of credit under this revolving credit facility.

Short-term borrowings were as follows:
At December 31, (in millions)
2015
 
2014
Credit facility borrowings, weighted average interest rate of 1.28% at December 31, 2015
$
15.0

 
$


Given their maturity and turnover is less than 90 days, cash flows related to the borrowings and repayments of the revolving credit facility are presented net in the Statements of Consolidated and Combined Cash Flows.
8.    Gain on Sale of Assets
The Partnership recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. For the years ended December 31, 2015, 2014 and 2013, gains on conveyances amounted to $52.3 million, $34.5 million and $7.3 million, respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $35.8 million received by CEVCO from CNX Gas Company LLC during the year ended December 31, 2015, for the lease of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. As of December 31, 2015 and 2014, deferred gains of approximately $8.1 million and $19.6 million, respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated and 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.

89

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

9.
Property, Plant and Equipment

The Partnership’s property, plant and equipment on the Consolidated and Combined Balance Sheets are classified as follows:
At December 31, (in millions)
2015
 
2014
 
 
 
Predecessor
Property, plant and equipment
 
 
 
Pipeline and other transmission assets
$
6,120.0

 
$
5,328.2

Storage facilities
1,370.1

 
1,326.5

Gas stored base gas
299.5

 
299.5

Gathering and processing facilities
370.2

 
263.3

Construction work in process
463.5

 
454.2

General plant, software, and other assets
307.6

 
259.9

Property, plant and equipment
8,930.9

 
7,931.6

Accumulated Depreciation and Amortization
(2,960.1
)
 
(2,971.4
)
Net Property, plant and equipment
$
5,970.8

 
$
4,960.2

The table below lists the Partnership's applicable annual depreciation rates:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Depreciation rates
 
 
 
 
 
Pipeline and other transmission assets
1.00% - 1.73%
 
1.00% - 2.55%
 
1.50 % - 2.55%
Storage facilities
2.19% - 3.00%
 
2.19% - 3.30%
 
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%
10.
Goodwill
The Partnership 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, referred to as the Columbia Gas Transmission Operations reporting unit, which is consistent with the level of discrete financial information reviewed by management. The Columbia Gas Transmission Operations reporting unit includes the following entities: Columbia Gas Transmission (including its equity method investment in the Millennium Pipeline joint venture), Columbia Gulf and the equity method investment in Hardy Storage. All of the Partnership's goodwill relates to NiSource's acquisition of CEG in 2000, which was contributed to the Partnership prior to the IPO. The Partnership's goodwill assets at December 31, 2015 and December 31, 2014 were $1,975.5 million.
The Predecessor completed a quantitative ("step 1") fair value measurement of the 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 Gas Transmission Operations for the May 1, 2012 test, the Partnership 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 each reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012.

90

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Under the market approach, the Partnership 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 with the assistance of a third-party valuation firm, 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 its carrying value, indicating that no impairment exists under step 1 of the annual impairment test.
Certain key assumptions used in determining the fair value of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Partnership used the discount rate of 5.60% for Columbia Gas Transmission Operations, resulting in excess fair value of approximately $1,643.0 million.
GAAP 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 Partnership applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2015. For the current year test, the Partnership 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 the reporting unit fair value is less than the reporting unit carrying value.
The Partnership considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. The Partnership reviewed the market capitalization method due to the recent decline in the Partnership's unit price. Following this review, the Partnership determined there were no indicators that would require goodwill impairment testing subsequent to May 1, 2015.
11.
Asset Retirement Obligations
Changes in the Partnership’s liability for asset retirement obligations for the years 2015 and 2014 are presented in the table below:
(in millions)
2015
 
2014
 
 
 
Predecessor
Balance as of January 1,
$
23.2

 
$
26.3

Noncontributed net parent investment adjustments(1)
(0.4
)
 

Accretion expense
1.2

 
1.5

Additions
4.1

 
2.2

Settlements

 
(6.6
)
Change in estimated cash flows
(2.8
)
 
(0.2
)
Balance as of December 31,
$
25.3

 
$
23.2

(1) Reflects the removal of amounts related to Crossroads Pipeline Company, which was included in the Predecessor, but was not contributed to the Partnership.
The asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl ("PCB") remediation and asbestos removal at several compressor and measuring stations. The Partnership recognizes that certain assets, which include gas pipelines and natural gas storage wells, will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified.

91

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

12.
Regulatory Matters
Regulatory Assets and Liabilities

Current and noncurrent regulatory assets and liabilities were comprised of the following items:
At December 31, (in millions)
2015
 
2014
 
 
 
Predecessor
Assets
 
 
 
Unrecognized pension benefit and other postretirement benefit costs
$
127.1

 
$
120.9

Other postretirement costs
8.9

 
10.8

Deferred taxes on AFUDC equity

 
21.8

Other
3.1

 
4.5

Total Regulatory Assets
$
139.1

 
$
158.0

At December 31, (in millions)
2015
 
2014
 
 
 
Predecessor
Liabilities
 
 
 
Cost of removal
$
153.5

 
$
156.2

Regulatory effects of accounting for income taxes

 
10.9

Unrecognized pension benefit and other postretirement benefit costs
0.6

 
8.3

Other postretirement costs
155.6

 
117.3

Other
1.2

 
2.9

Total Regulatory Liabilities
$
310.9

 
$
295.6

No regulatory assets are earning a return on investment at December 31, 2015. Regulatory assets of $7.2 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 7 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 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 Partnership 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. The regulatory asset was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level.
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 some 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, which is being amortized to earnings in association with depreciation on related

92

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

property. The regulatory liability was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level.
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.
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 Partnership’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 $25.0 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 14.0% revenue requirement with a portion designated as a recovery of 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 a $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 $100.0 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15.0% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term.
On January 28, 2016, Columbia Gas Transmission received FERC approval of its December 2015 filing to recover costs associated with the third year of its comprehensive system modernization program. Total program adjusted spend to date is $937.1 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. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016.

Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf ’s existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf intends to file a cost and revenue study with FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. The outcome of this proceeding to Columbia Gulf is not currently determinable.

Cost Recovery Trackers and other similar mechanisms. Under section 4 of the NGA, 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.

93

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015.

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. The recoveries and costs are both reflected in operating expenses.
13.
Equity Method Investments
Certain investments of the Partnership are accounted for under the equity method of accounting. These investments are recorded within "Unconsolidated Affiliates" on the Partnership's Consolidated and Combined Balance Sheets and the Partnership's portion of the results are reflected in "Equity Earnings in Unconsolidated Affiliates" on the Partnership's Statements of Consolidated and Combined Operations. In the normal course of business, the Partnership engages in various transactions with these unconsolidated affiliates. During the year ended December 31, 2015, the Partnership had billed approximately $13.1 million for services and other costs to Millennium Pipeline. Contributions are made to these equity investees to fund the Partnership's share of projects.

The following is a list of the Partnership's equity method investments at December 31, 2015: 
Investee
Type of Investment
% of Voting Power or Interest Held
Hardy Storage Company, LLC
LLC Membership
49.0
%
Pennant Midstream, LLC
LLC Membership
47.5
%
Millennium Pipeline Company, L.L.C.
LLC Membership
47.5
%

94

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in aggregate, material to the Partnership's business, the following table contains condensed summary financial data.
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Millennium Pipeline
 
 
 
 
 
Statement of Income Data:
 
 
 
 
 
Net Revenues
$
206.3

 
$
190.5

 
$
157.8

Operating Income
136.1

 
128.8

 
101.3

Net Income
98.0

 
89.6

 
63.0

Balance Sheet Data:
 
 
 
 
 
Current Assets
35.7

 
32.1

 
38.3

Noncurrent Assets
987.1

 
1,016.3

 
1,033.8

Current Liabilities
44.4

 
42.6

 
58.8

Noncurrent Liabilities
535.8

 
568.3

 
599.7

Total Members’ Equity
442.6

 
437.5

 
413.6

Contribution/Distribution Data:(1)
 
 
 
 
 
Contributions to Millennium Pipeline
1.4

 
2.6

 
16.6

Distribution of earnings from Millennium Pipeline
47.5

 
35.6

 
29.0

Hardy Storage
 
 
 
 
 
Statement of Operations Data:
 
 
 
 
 
Net Revenues
$
23.4

 
$
23.6

 
$
24.4

Operating Income
15.3

 
16.1

 
16.5

Net Income
10.3

 
10.6

 
10.6

Balance Sheet Data:
 
 
 
 
 
Current Assets
12.1

 
12.0

 
12.5

Noncurrent Assets
155.5

 
157.4

 
160.2

Current Liabilities
19.3

 
17.1

 
18.3

Noncurrent Liabilities
68.5

 
77.4

 
85.7

Total Members’ Equity
79.8

 
74.9

 
68.7

Contribution/Distribution Data:(1)
 
 
 
 
 
Contributions to Hardy Storage

 

 

Distribution of earnings from Hardy Storage
2.6

 
2.2

 
3.1

Pennant
 
 
 
 
 
Statement of Operations Data:
 
 
 
 
 
Net Revenues
$
34.6

 
$
8.5

 
$
2.0

Operating Income (Loss)
17.8

 
(2.4
)
 
1.3

Net Income (Loss)
17.8

 
(2.4
)
 
1.3

Balance Sheet Data:
 
 
 
 
 
Current Assets
11.0

 
23.7

 
34.1

Noncurrent Assets
389.6

 
380.0

 
231.9

Current Liabilities
8.4

 
8.6

 
11.4

Total Members’ Equity
392.2

 
395.1

 
254.6

Contribution/Distribution Data:(1)
 
 
 
 
 
Contributions to Pennant

 
66.6

 
108.9

Distribution of earnings from Pennant
7.1

 

 

Return of capital from Pennant
16.0

 

 

(1)Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.

95

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

14.
Income Taxes
The components of income tax expense were as follows:
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Income Taxes
 
 
 
 
 
Current
 
 
 
 
 
Federal
$
12.0

 
$
21.3

 
$
(16.1
)
State
1.2

 
5.8

 
(11.4
)
Total Current
13.2

 
27.1

 
(27.5
)
Deferred
 
 
 
 
 
Federal
8.8

 
117.7

 
155.9

State
1.9

 
21.7

 
24.1

Total Deferred
10.7

 
139.4

 
180.0

Deferred Investment Credits

 
(0.1
)
 
(0.1
)
Total Income Taxes
$
23.9

 
$
166.4

 
$
152.4

Total income taxes 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, (in millions)
2015
 
2014
 
2013
 
 
 
 
 
Predecessor
 
Predecessor
Book income before income taxes
$
554.1

 
 
 
$
435.5

 
 
 
$
419.3

 
 
Tax expense at statutory federal income tax rate
193.9

 
35.0
 %
 
152.4

 
35.0
 %
 
146.8

 
35.0
 %
Increases (reductions) in taxes resulting from:
 
 
 
 
 
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
2.0

 
0.4

 
17.9

 
4.1

 
8.2

 
1.9

Income not subject to income tax at the partnership level
(170.6
)
 
(30.9
)
 

 

 

 

AFUDC-Equity
(0.3
)
 

 
(3.8
)
 
(0.9
)
 
(2.4
)
 
(0.6
)
Other, net
(1.1
)
 
(0.2
)
 
(0.1
)
 

 
(0.2
)
 

Total Income Taxes
$
23.9

 
4.3
 %
 
$
166.4

 
38.2
 %
 
$
152.4

 
36.3
 %
The effective income tax rates were 4.3%, 38.2%, and 36.3% in 2015, 2014 and 2013, respectively. The effective tax rate for 2015 differs from the federal tax rate of 35% primarily due to the income received following the Partnership's IPO that is not subject to income tax at the partnership level. The effective tax rate is impacted by the Partnership’s IPO which modified the ownership structure and now reflects Partnership earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes.
The effective tax rate for 2014 and 2013 differs from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, as well as other permanent book-to-tax differences.
Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items.
The Partnership had no unrecognized tax benefits related to uncertain tax positions as of December 31, 2015. As of December 31, 2014 and 2013, the Predecessor financial statements included unrecognized tax benefits of zero and $0.1 million, respectively.
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

96

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The principal components of the Partnership’s net deferred tax liability were as follows:
At December 31, (in millions)
2015
 
2014
 
 
 
Predecessor
Deferred tax liabilities
 
 
 
Accelerated depreciation and other property differences
$
1.0

 
$
1,235.3

Pension and other postretirement/postemployment benefits

 
24.3

Other regulatory assets

 
62.8

Other, net

 
77.9

Total Deferred Tax Liabilities
1.0

 
1,400.3

Deferred tax assets
 
 
 
Deferred investment tax credits and other regulatory liabilities

 
(116.7
)
Net operating loss carryforward and AMT credit carryforward

 
(67.8
)
Other accrued liabilities

 
(1.4
)
Total Deferred Tax Assets

 
(185.9
)
Net Deferred Tax Liabilities less Deferred Tax Assets
1.0

 
1,214.4

Less: Deferred income taxes related to current assets and liabilities

 
(24.6
)
Non-Current Deferred Tax Liabilities
$
1.0

 
$
1,239.0

15.
Pension and Other Postretirement Benefits
CPG provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of subsidiaries of Columbia OpCo. Prior to the Separation, employees of subsidiaries of Columbia OpCo were covered by defined contributions plans and noncontributory defined benefit plans provided by NiSource. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, CPG provides health care and life insurance benefits for certain retired employees of subsidiaries of Columbia OpCo. The majority of employees may become eligible for these benefits if they reach retirement age while working for subsidiaries of Columbia OpCo. The expected cost of such benefits is accrued during the employees’ years of service. Current rates charged to customers of subsidiaries of Columbia OpCo include postretirement benefit costs. Cash contributions are remitted to grantor trusts.
As of July 1, 2015, in connection with the Separation, accrued pension and postretirement benefit obligations for subsidiaries of Columbia OpCo participants and related plan assets were transferred from NiSource to CPG. Subsidiaries of Columbia OpCo are participants in the consolidated CPG defined benefit retirement plans ("the Plans"), and therefore, subsidiaries of Columbia OpCo are allocated a ratable portion of CPG's grantor trusts for the Plans in which its employees and retirees participate. As a result, the Partnership follows multiple employer accounting under the provisions of GAAP.
Pension and Other Postretirement Benefit Plans’ Asset Management. CPG 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 may be 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.
To establish a long-term rate of return for plan assets assumption, past historical capital market returns and a proprietary forecast are evaluated. The 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.

97

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 CPG plan assets represents a long-term view and are listed in the following table.
In 2012, an 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, 2015 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 at December 31, 2015 and December 31, 2014:
December 31, 2015
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
$
115.9

 
39.4
%
 
$
95.3

 
44.6
%
International Equities
51.4

 
17.5
%
 
40.1

 
18.7
%
Fixed Income
101.5

 
34.4
%
 
71.8

 
33.6
%
Cash/Other
25.5

 
8.7
%
 
6.7

 
3.1
%
Total
$
294.3

 
100.0
%
 
$
213.9

 
100.0
%
 
 
 
 
 
 
 
 
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
%
 

 
%
Cash/Other
4.2

 
1.4
%
 
0.6

 
0.3
%
Total
$
304.8

 
100.0
%
 
$
211.6

 
100.0
%
The categorization of investments into the asset classes in the table above are based on definitions established by the CPG Benefits Committee.

98

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the CPG Pension Plan Trust and OPEB investment assets at fair value as of December 31, 2015 and 2014. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total CPG Pension Plan Trust and OPEB investment assets at fair value classified within Level 3 were zero and $15.3 million as of December 31, 2015 and December 31, 2014, respectively. Such amounts were approximately zero and 3% of the CPG Pension Plan Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2015 and 2014, respectively.
Valuation Techniques Used to Determine Fair Value:
Level 1 Measurements
Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.
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, 2015, there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets.

99

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts:
Fair Value Measurements (in millions)
December 31,
2015
 
Quoted Prices in Active
Markets for Identical Assets (Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs (Level 3)
Pension plan assets
 
 
 
 
 
 
 
Cash
$
0.8

 
$
0.8

 
$

 
$

Equity securities
 
 
 
 
 
 
 
International equities
5.4

 
5.4

 

 

Fixed income securities
 
 
 
 
 
 
 
Government
7.1

 

 
7.1

 

Corporate
10.8

 

 
10.8

 

Commingled funds
 
 
 
 
 
 
 
Short-term money markets
25.5

 

 
25.5

 

U.S. equities
115.9

 

 
115.9

 

International equities
45.7

 

 
45.7

 

Fixed income
83.1

 

 
83.1

 

Pension plan assets subtotal
294.3

 
6.2

 
288.1

 

Other postretirement benefit plan assets
 
 
 
 
 
 
 
Commingled funds
 
 
 
 
 
 
 
Short-term money markets
6.8

 

 
6.8

 

U.S. equities
13.0

 

 
13.0

 

Mutual funds
 
 
 
 
 
 
 
U.S. equities
82.3

 
82.3

 

 

International equities
40.1

 
40.1

 

 

Fixed income
71.7

 
71.7

 

 

Other postretirement benefit plan assets subtotal
213.9

 
194.1

 
19.8

 

Due to brokers, net(1)
(0.3
)
 
 
 
 
 
 
Accrued investment income/dividends
0.5

 
 
 
 
 
 
Total pension and other postretirement benefit plan assets
$
508.4

 
$
200.3

 
$
307.9

 
$

(1) This class represents pending trades with brokers.

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, 2015:
 
(in millions)
Balance at
January 1, 2015
 
Total gains or
losses (unrealized
/ realized)
 
Purchases
 
(Sales)
 
Transfers
into/(out of)
level 3
 
Separation Allocation(1)
 
Balance at
December 31,  2015
Fixed income securities
 
 
 
 
 
 
 
 
 
 
 
 
 
Other fixed income
$
0.1

 
$

 
$

 
$

 
$

 
$
(0.1
)
 
$

Private equity limited partnerships
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. multi-strategy
7.3

 

 

 

 

 
(7.3
)
 

International multi-strategy
4.6

 

 

 

 

 
(4.6
)
 

Distressed opportunities
1.0

 

 

 

 

 
(1.0
)
 

Real estate
2.3

 

 

 

 

 
(2.3
)
 

Total
$
15.3

 
$

 
$

 
$

 
$

 
$
(15.3
)
 
$

(1) Level 3 assets were not contributed to the Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation.

100

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts:
Fair Value Measurements (in millions)
December 31,
2014
 
Quoted Prices in Active
Markets for Identical Assets (Level 1)
 
Significant Other
Observable Inputs (Level 2)
 
Significant
Unobservable Inputs (Level 3)
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

 

Mortgages/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 in the United States.
(2) 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 outside the United States.
(3) This class represents pending trades with brokers.

101

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2014:
(in millions)
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
 
 
 
 
 
 
 
 
 
 
 
Other fixed income
$

 
$

 
$
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

Distress 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

As noted above, the Partnership follows multiple employer accounting under the provisions of GAAP and therefore, is allocated a ratable portion of the CPG’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 Partnership is allocated a portion of investment gains and losses based on its percentage of the total CPG projected benefit obligation.


102

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG 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 Partnership’s Consolidated and Combined Balance Sheets at December 31 based on a December 31 measurement date:
 
Pension Benefits
 
Other Postretirement Benefits
(in millions)
2015
 
2014
 
2015
 
2014
 
 
 
Predecessor
 
 
 
Predecessor
Change in projected benefit obligation(1)
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
345.2

 
$
327.1

 
$
108.9

 
$
105.5

Service cost
5.3

 
4.8

 
1.0

 
1.1

Interest cost
12.5

 
13.7

 
4.0

 
4.6

Plan participants’ contributions

 

 
1.6

 
1.9

Actuarial loss (gain)
(7.3
)
 
20.0

 
(11.6
)
 
4.6

Benefits paid
(23.5
)
 
(20.4
)
 
(7.5
)
 
(9.1
)
Estimated benefits paid by incurred subsidy

 

 
0.2

 
0.3

Contributed/noncontributed projected benefit obligation(2)
(4.6
)


 
(3.2
)
 

Projected benefit obligation at end of year
$
327.6

 
$
345.2

 
$
93.4

 
$
108.9

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
$
304.7

 
$
299.1

 
$
211.6

 
$
198.8

Actual return on plan assets
0.6

 
19.3

 
(2.0
)
 
9.2

Employer contributions
16.5

 
6.7

 
11.3

 
10.8

Plan participants’ contributions

 

 
1.6

 
1.9

Benefits paid
(23.5
)
 
(20.4
)
 
(7.5
)
 
(9.1
)
Contributed/noncontributed plan assets(2)
(4.0
)
 

 
(1.1
)
 

Fair value of plan assets at end of year
$
294.3

 
$
304.7

 
$
213.9

 
$
211.6

Funded status at end of year
$
(33.3
)
 
$
(40.5
)
 
$
120.5


$
102.7

Amounts recognized in the statement of financial position consist of:
 
 
 
 
 
 
 
Noncurrent assets
$

 
$

 
$
120.5

 
$
109.8

Current liabilities
(0.1
)
 

 

 

Noncurrent liabilities
(33.2
)
 
(40.5
)
 

 
(7.1
)
Net amount recognized at end of year(3)
$
(33.3
)
 
$
(40.5
)
 
$
120.5

 
$
102.7

Amounts recognized as regulatory assets/liabilities(4)
 
 
 
 
 
 
 
Unrecognized prior service (credit) cost
$
(3.0
)
 
$
(4.0
)
 
$
0.1

 
$
0.1

Unrecognized actuarial loss (gain)
130.3

 
124.5

 
(0.4
)
 
(8.3
)
Total recognized regulatory assets (liabilities)
$
127.3

 
$
120.5

 
$
(0.3
)
 
$
(8.2
)
(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) Reflects the removal of amounts related to Crossroads Pipeline Company and CPGSC, which were included in the Predecessor, but were not contributed to the Partnership, as well as the inclusion of CNS Microwave, which was not part of the Predecessor.
(3) The Partnership recognizes in its Consolidated and Combined 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.
(4) The Partnership determined that the future recovery of pension and other postretirement benefits costs is probable. The Partnership recorded regulatory assets and liabilities of $127.1 million and $0.6 million, respectively, as of December 31, 2015, and $120.9 million and $8.3 million, respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss.
The Partnership’s accumulated benefit obligation for its pension plans was $327.6 million and $345.2 million as of December 31, 2015 and 2014, 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 Partnership's pension plans were underfunded by $33.3 million at December 31, 2015, compared to being underfunded by $40.5 million by December 31, 2014. The improvement in the funded status was due primarily to an increase in the discount rate from the prior measurement date and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed $16.5 million and $6.7 million to its pension plans in 2015 and 2014, respectively.

103

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The Partnership’s funded status for its other postretirement benefit plans improved by $17.8 million to an overfunded status of $120.5 million primarily due to favorable claims experience and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed approximately $11.3 million and $10.8 million to its other postretirement benefit plans in 2015 and 2014, respectively. No amounts of the Partnership’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG or any of its subsidiaries in 2016.
In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plans' 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 Partnership’s various plans as of December 31:
 
Pension Benefits
 
Other Postretirement  Benefits
  
2015
 
2014
 
2015
 
2014
 
 
 
Predecessor
 
 
 
Predecessor
Weighted-average assumptions to determine benefit obligation
 
 
 
 
 
 
 
Discount Rate
4.05
%
 
3.64
%
 
4.28
%
 
3.95
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
 
 
 
Health Care Trend Rates
 
 
 
 
 
 
 
Trend for Next Year
 
 
 
 
8.38
%
 
6.90
%
Ultimate Trend
 
 
 
 
4.50
%
 
4.50
%
Year Ultimate Trend Reached
 
 
 
 
2022

 
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:
(in millions)
1% point increase
 
1% point decrease
Effect on service and interest components of net periodic cost
$
0.1

 
$
(0.1
)
Effect on accumulated postretirement benefit obligation
2.5

 
(2.3
)
The Partnership expects to make contributions of approximately $0.1 million to its pension plans and approximately $0.9 million to its postretirement medical and life plans in 2016.

104

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 Partnership's benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees:
(in millions)
Pension Benefits
 
Other
Postretirement Benefits
 
Federal
Subsidy Receipts
Year(s)
 
 
 
 
 
2016
$
27.2

 
$
6.2

 
$
0.3

2017
27.1

 
6.2

 
0.3

2018
27.9

 
6.3

 
0.3

2019
28.0

 
6.4

 
0.3

2020
30.0

 
6.4

 
0.3

2021-2025
145.8

 
31.4

 
1.2

The following table provides the components of the plans’ net periodic benefits cost for the years ended December 31, 2015, 2014 and 2013:
 
Pension Benefits
 
Other Postretirement
Benefits
(in millions)
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
 
 
 
Predecessor
 
Predecessor
Components of Net Periodic Benefit Cost (Income)
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
5.3

 
$
4.8

 
$
4.8

 
$
1.0

 
$
1.1

 
$
1.5

Interest cost
12.5

 
13.7

 
12.6

 
4.0

 
4.6

 
4.9

Expected return on assets
(23.6
)
 
(23.8
)
 
(22.0
)
 
(17.4
)
 
(16.5
)
 
(13.5
)
Amortization of prior service (credit) cost
(0.9
)
 
(1.0
)
 
(0.9
)
 
0.1

 
0.1

 
0.1

Recognized actuarial loss (gain)
8.2

 
6.6

 
10.6

 
(0.2
)
 
(0.1
)
 
1.0

Net Periodic Benefit Cost (Income)
1.5

 
0.3

 
5.1

 
(12.5
)
 
(10.8
)
 
(6.0
)
Settlement loss

 

 
12.4

 

 

 

Total Net Periodic Benefit Cost (Income)
$
1.5

 
$
0.3

 
$
17.5

 
$
(12.5
)
 
$
(10.8
)
 
$
(6.0
)
The $1.2 million increase in the actuarially-determined pension benefit cost is due primarily to decreased discount rates and unfavorable asset returns in 2015 compared to 2014. For its other postretirement benefit plans, the Partnership recognized $12.5 million in net periodic benefit income in 2015 compared to net periodic benefit income of $10.8 million in 2014 due primarily to favorable claims experience, offset by a decrease in discount rates in 2015 compared to 2014.

105

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table provides the key assumptions that were used to calculate the net periodic benefits cost for the Partnership’s various plans:
 
Pension Benefits
 
 Other Postretirement
Benefits
  
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
 
 
 
Predecessor
 
Predecessor
Weighted-average assumptions to determine net periodic benefit cost
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
3.84
%
 
4.34
%
 
3.36
%
 
4.09
%
 
4.74
%
 
3.92
%
Expected Long-Term Rate of Return on Plan Assets
8.20
%
 
8.30
%
 
8.30
%
 
8.06
%
 
8.14
%
 
8.15
%
Rate of Compensation Increases
4.00
%
 
4.00
%
 
4.00
%
 
 
 
 
 
 
The Partnership believes it is appropriate to assume an 8.20% and 8.06% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2015 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
(in millions)
2015
 
2014
 
2015
 
2014
 
 
 
Predecessor
 
 
 
Predecessor
Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities
 
 
 
 
 
 
 
Net actuarial loss
$
14.1

 
$
24.4

 
$
7.8

 
$
11.7

Less: amortization of prior service (credit) cost
0.9

 
1.0

 
(0.1
)
 

Less: amortization of net actuarial (gain) loss
(8.2
)
 
(6.6
)
 
0.2

 

Total recognized in regulatory assets/liabilities
$
6.8

 
$
18.8

 
$
7.9

 
$
11.7

Amount recognized in net periodic benefit cost and regulatory assets/liabilities
$
8.3

 
$
19.1

 
$
(4.6
)
 
$
0.9

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 2016 for the pension plans are $10.1 million, $(0.9) million and zero, respectively, and for other postretirement benefit plans are $0.2 million, $0.1 million and zero, respectively.
16.
Fair Value
The Partnership 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, short-term borrowings and short-term borrowings-affiliated. The Partnership’s long-term debt-affiliated is 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. As of December 31, 2015, the fair value approximates carrying value as these securities bear interest at variable rates. These fair value measurements are classified as Level 2 within the

106

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

fair value hierarchy. For the years ended December 31, 2015 and 2014, 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, (in millions)
Carrying
Amount
2015
 
Estimated
Fair Value
2015
 
Carrying
Amount
2014
 
Estimated
Fair Value
2014
 
 
 
 
 
Predecessor
Current portion of long-term debt-affiliated
$

 
$

 
$
115.9

 
$
120.0

Long-term debt-affiliated
630.9

 
630.9

 
1,472.8

 
1,550.4

17.Other Commitments and Contingencies

A.Guarantees and Indemnities. In the normal course of its business, the Partnership and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of the parent or certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to the parent or a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the parent or the subsidiaries' intended commercial purposes. The total guarantees and indemnities in existence at December 31, 2015 and the years in which they expire were:
(in millions)
Total
2016
2017
2018
2019
2020
After
Guarantees of debt
$
2,750.0

$

$

$
500.0

$

$
750.0

$
1,500.0

Letters of credit
18.1

18.1






Total commercial commitments
$
2,768.1

$
18.1

$

$
500.0

$

$
750.0

$
1,500.0


Guarantees of Debt. OpCo GP and Columbia OpCo (together with CEG, the "Guarantors") have guaranteed payment of $2,750.0 million in aggregated principal amount of CPG's senior notes. Each Guarantor is required to comply with covenants under the debt indenture and in the event of default the Guarantors would be obligated to pay the debt's principal and related interest. The Partnership does not anticipate that OpCo GP or Columbia OpCo will have any difficulty maintaining compliance.
The guarantees of any Guarantor may be released under certain circumstances. First, if CPG discharges or defeases its obligations with respect to any series of CPG’s senior notes, then any guarantee will be released with respect to that series. Second, if no event of default has occurred and is continuing under the indenture, a Guarantor will be automatically and unconditionally released and discharged from its guarantee (i) at any time after June 1, 2018, upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not CPG’s affiliate, of all of CPG’s direct or indirect limited partnership, limited liability or other equity interests in the Guarantor; (ii) upon the merger of a guarantor into CPG or any other Guarantor or the liquidation and dissolution of such Guarantor; or (iii) at any time after June 1, 2018, upon release of all guarantees or other obligations of the Guarantor with respect to any of CPG’s funded debt, except CPG’s senior notes.
Lines and Letters of Credit. The Partnership maintains a $500.0 million senior revolving credit facility, of which $50.0 million is 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. As of December 31, 2015, the Partnership had $15.0 million in outstanding borrowings and no letters of credit under the revolving credit facility. CPG maintains a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. CPG expects that $750.0 million of the facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of the facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG's $1,000.0 million commercial paper program. OpCo GP and Columbia OpCo, together with CEG, have each fully guaranteed the CPG credit facility. As of December 31, 2015, CPG had no borrowings outstanding and $18.1 million in letters of credit outstanding under its revolving credit facility.

107

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG has established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the "Securities Act"). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. OpCo GP and Columbia OpCo, together with CEG, have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.
Other Legal Proceedings. In the normal course of its business, the Partnership has been named as a defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material impact on the Partnership’s consolidated and combined financial statements.
B.Environmental Matters. The Partnership's operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. The Partnership believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary material permits to conduct its operations.
It is the Partnership'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 Partnership records accruals to cover environmental remediation at various sites. The current portion of this accrual is included in “Other accruals” in the Consolidated and Combined Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated and Combined Balance Sheets.
Air

The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. The actions listed below could require further reductions in emissions from various emission sources. The Partnership will continue to closely monitor developments in these matters.
National Ambient Air Quality Standards. The federal CAA requires the EPA to set NAAQS for particulate matter and five other pollutants considered harmful to public health and the environment. Periodically, the EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by gas transmission operations.
The following NAAQS were recently added or modified:
Ozone: On October 1, 2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 ppb under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is required to include an adequate margin of safety in establishing the primary ozone standard for protection of public health, whereas the secondary ozone standard is intended to improve protection for trees, plants and ecosystems. The final rule becomes effective sixty days after the rule is published in the Federal Register. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With the EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations. Based on the current version of the rule, the Partnership does not expect a material impact on its operations.
Nitrogen Dioxide (NO2): The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop

108

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing Partnership combustion sources may need to be assessed and mitigated. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.
Climate Change. The EPA has already promulgated regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the U.S. on an annual basis. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.
New Source Performance Standards: On August 18, 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. Semiannual leak detection and repair requirements using optical gas imaging are proposed for all components at new or existing compressor stations. Existing compressor stations trigger leak detection and repair requirements if any unit at the facility is modified. The EPA proposed additional requirements for any new or modified centrifugal or reciprocating compressors. Replacement of wet seals with dry seals or demonstrating a 95% reduction of methane emissions from wet seals is proposed for centrifugal compressors and rod packing replacement for reciprocating compressors is proposed every 26,000 hours of operation or every three years. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.
C.Operating Lease Commitments. The Partnership leases assets in several areas of its operations. Payments made in connection with operating leases were $18.5 million in 2015, $14.9 million in 2014 and $13.4 million in 2013, 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:
(in millions)
Operating
Leases (1)
2016
$
4.5

2017
5.9

2018
5.5

2019
4.8

2020
4.7

After
21.2

Total future minimum payments
$
46.6

(1) Operating lease expense 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.

D.Service Obligations. The Partnership has entered into various service agreements whereby the Partnership is contractually obligated to make certain minimum payments in future periods. The Partnership has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2016 to 2025, require the Partnership to pay fixed monthly charges.


109

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The estimated aggregate amounts of minimum fixed payments at December 31, 2015, were:
(in millions)
Pipeline
Service
Agreements
2016
$
51.5

2017
49.5

2018
42.0

2019
25.4

2020
24.2

After
66.8

Total future minimum payments
$
259.4

18.Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:
(in millions)
Gains and Losses on Cash Flow Hedges(1)
 
Pension and OPEB Items(1)
 
Accumulated
Other
Comprehensive
Loss(1)
Balance as of January 1, 2013 - Predecessor
$
(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 - Predecessor
$
(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 - Predecessor
$
(16.6
)
 
$
(0.1
)
 
$
(16.7
)
Predecessor net tax liabilities not assumed by Columbia OpCo(2)
$
(10.2
)
 
$
(0.1
)
 
(10.3
)
Other comprehensive income before reclassifications

 
(0.3
)
 
(0.3
)
Amounts reclassified from accumulated other comprehensive income(3)
1.5

 
0.1

 
1.6

Net current-period other comprehensive income
1.5

 
(0.2
)
 
1.3

Allocation of accumulated other comprehensive loss to noncontrolling interest
(21.4
)
 
(0.3
)
 
(21.7
)
Balance as of December 31, 2015
$
(3.9
)
 
$
(0.1
)
 
$
(4.0
)
 
 (1)All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits.
(2) Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that will continue to be borne by the Partnership post-IPO.
(3) Includes amounts allocated to noncontrolling interest.
Equity Method Investment
During 2008, Millennium Pipeline, in which the Partnership 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 Partnership is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss of $25.0 million, before 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

110

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $25.0 million and $16.6 million at December 31, 2015 and December 31, 2014, respectively, is included in unrealized losses on cash flow hedges above.
19.
Other, Net
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
AFUDC Equity
$
28.3

 
$
11.0

 
$
6.8

Miscellaneous(1)
3.7

 
(2.2
)
 
10.8

Total Other, net
$
32.0

 
$
8.8

 
$
17.6

(1) Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.
20.
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 Chief Executive Officer of OpCo GP is the chief operating decision maker for the periods presented.
At December 31, 2015, the Partnership’s operations comprise one operating segment. The Partnership'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. The chief operating decision maker evaluates the performance of the Partnership operations and determines how to allocate resources on a consolidated basis.
21.Supplemental Cash Flow Information

The following tables provide additional information regarding the Partnership’s Statements of Consolidated and Combined Cash Flows for the years ended December 31, 2015, 2014 and 2013:
Year Ended December 31, (in millions)
2015
 
2014
 
2013
 
 
 
Predecessor
 
Predecessor
Supplemental Disclosures of Cash Flow Information
 
 
 
 
 
Non-cash transactions:
 
 
 
 
 
Capital expenditures included in current liabilities(1)
$
122.7

 
$
78.5

 
$
53.1

Schedule of interest and income taxes paid:
 
 
 
 
 
Cash paid for interest, net of interest capitalized amounts
$
40.3

 
$
53.6

 
$
39.5

Cash paid for income taxes
0.2

 
21.5

 
10.2

(1)Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated and Combined Balance Sheets.

111

Columbia Pipeline Partners LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

22. Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for greater than 10% of total operating revenues in the years ended December 31, 2015, 2014 and 2013. The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended December 31, 2015, 2014 and 2013:

Year Ended December 31,
2015
 
2014
 
2013
(in millions)
Total Operating Revenues
 
Percentage of Total Operating Revenues
 
Total Operating Revenues
 
Percentage of Total Operating Revenues
 
Total Operating Revenues
 
Percentage of Total Operating Revenues
 
 
 
 
 
Predecessor
 
Predecessor
Columbia Gas of Ohio(1)
$
167.3

 
12.6
%
 
$
168.5

 
12.5
%
 
$
167.5

 
14.2
%
(1) Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release arrangements with third parties which ultimately can decrease the net revenue amount we receive from Columbia Gas of Ohio in any given period.

The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of the Partnership.
23.
Quarterly Financial Data (Unaudited)
 
(in millions, except per unit data)
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2015
 
 
 
 
 
 
 
Operating Revenues
$
339.2

 
$
315.6

 
$
320.0

 
$
357.0

Operating Income
162.0

 
109.2

 
142.8

 
136.3

Net Income
131.2

 
107.8

 
144.6

 
146.6

Predecessor net income prior to IPO on February 11, 2015
42.7

 

 

 

Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO
75.2

 
91.5

 
122.6

 
124.2

Net income attributable to limited partners subsequent to IPO
13.3

 
16.3

 
22.0

 
22.4

Net Income Per Limited Partner Unit (basic and diluted)
 
 
 
 
 
 
 
Common Units
0.13

 
0.17

 
0.22

 
0.22

Subordinated Units
0.13

 
0.16

 
0.22

 
0.22

2014
 
 
 
 
 
 
 
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

24. Subsequent Events
Partnership Distribution. On January 29, 2016, the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period October 1, 2015, through December 31, 2015, of $0.1800 per unit, or $18.1 million in total. This distribution is payable on February 19, 2016, to unitholders of record as of February 11, 2016.
Columbia OpCo Distribution. On February 16, 2016, Columbia OpCo distributed $129.2 million of earnings to limited partners. The Partnership received a distribution of $20.3 million and CEG received $108.9 million based on the respective ownership percentages in Columbia OpCo.

112


Columbia Pipeline Partners LP
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
The Partnership's chief executive officer and its 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)). The Partnership's 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 the Partnership's chief 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, the Partnership's chief 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 at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
The Partnership's management, including the Partnership’s principal executive officer and principal financial officer, are responsible for establishing and maintaining the Partnership’s internal control over financial reporting, as such term is defined under Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The Partnership’s management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2015, the Partnership conducted an evaluation of its internal control over financial reporting. Based on this evaluation, the Partnership's management concluded that the Partnership’s internal control over financial reporting was effective as of the end of the period covered by this annual report.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Partnership’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Deloitte & Touche LLP, the Partnership’s independent registered public accounting firm, issued an attestation report on the Partnership’s internal controls over financial reporting which is contained in Item 8, “Financial Statements and Supplementary Data.”
Changes in Internal Controls
There have been no changes in the Partnership’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 Partnership’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.

113


Columbia Pipeline Partners LP
PART III


ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management of Columbia Pipeline Partners LP
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. CPG 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.
 
61
 
Director and Chief Executive Officer
Glen L. Kettering
 
60
 
Director and President
Stephen P. Smith
 
54
 
Director and Chief Financial Officer
Robert E. Smith
 
46
 
Director and General Counsel
Stanley G. Chapman, III
 
50
 
Director and Chief Commercial Officer
Shawn L. Patterson
 
42
 
Executive Vice President and Chief Operations Officer
G. Stephen Finley
 
64
 
Director
Thomas W. Hofmann
 
64
 
Director
Peggy A. Heeg
 
56
 
Director
Robert C. Skaggs, Jr. Mr. Skaggs was appointed to the board of directors in February 2015. He also serves as Chief Executive Officer, a position he has held since December 2014. Separately, Mr. Skaggs is Chairman of the Board and Chief Executive Officer of Columbia Pipeline Group, Inc. and is responsible for the strategic direction of the company. Prior to CPG’s Separation from NiSource Inc. in July 2015, Mr. Skaggs had served as CEO of NiSource since 2005 and President since 2004. Mr. Skaggs is a member of the board of directors of Cloud Peak Energy Inc. as well as the National Safety Council’s board of directors and the board of trustees at the Universities Research Association, Inc. He also is past chairman of the American Gas Association’s board of directors. He also is a trustee of the Columbia Pipeline Group Charitable Foundation, and has served in leadership roles for a variety of charitable, community and civic efforts. Mr. Skaggs earned a bachelor’s degree in economics from Davidson College, a law degree from West Virginia University and a master’s degree in business administration 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.
Glen L. Kettering. Mr. Kettering was appointed to the board of directors in February 2015. He also serves as President, a position he has held since December 2014. Separately, Mr. Kettering is President of Columbia Pipeline Group, Inc. and oversees all day to day operations as well as the execution of CPG’s capital investment, modernization and growth strategies. Before CPG’s Separation from NiSource Inc. in July 2015, Mr. Kettering served in a similar role as the Group CEO of NiSource’s CPG Business Unit. Prior to being named CPG Group CEO in 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 Transmission. Mr. Kettering earned a bachelor's degree in business administration from West Virginia University and a law degree from the West Virginia University

114

Columbia Pipeline Partners LP
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (continued)


College of Law. He is a member of the Energy Bar Association and the West Virginia State Bar. He also serves as a trustee of the Columbia Pipeline Group Charitable Foundation. 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.
Stephen P. Smith. Mr. Smith was appointed to the board of directors in September 2014. He also serves as Chief Financial Officer, a position he has held since December 2014. Separately, Mr. Smith is Executive Vice President and Chief Financial Officer of Columbia Pipeline Group, Inc. and is responsible for the company’s Finance functions. Prior to CPG’s Separation from NiSource Inc. in July 2015, Smith served in the same role at NiSource. 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. He serves as a Director and Audit Committee member of Natural Resource Partners, L.P., a publicly traded master limited partnership engaged in owning mineral reserve properties. Mr. Smith also is a Board Member of the Columbus Metropolitan Library Foundation and serves on its Finance & Audit Committee. Mr. Smith was selected to serve as a director because of his management expertise and his extensive financial background.
Robert E. Smith. Mr. Smith was appointed to the board of directors in February 2015. He also serves as General Counsel, a position he has held since December 2014. Separately, Mr. Smith is Senior Vice President and General Counsel of Columbia Pipeline Group, Inc. where he oversees all CPG Legal functions. Prior to CPG’s Separation from NiSource Inc. in July 2015, Mr. Smith served as Corporate Secretary, Vice President and Deputy General Counsel of NiSource. He joined NiSource in 2008 and was named Corporate Secretary in April 2013 where he oversaw the legal department’s corporate group and was responsible for the corporation’s corporate legal and governance work. Mr. Smith also serves as Chairman of the board of directors of Global Action, an international non-profit organization. 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.
Stanley G. Chapman, III. Mr. Chapman was appointed to the board of directors in February 2015. He also serves as Chief Commercial Officer, a position he has held since December 2014. Separately, Mr. Chapman is Executive Vice President & Chief Commercial Officer of Columbia Pipeline Group, Inc. where he is responsible for all commercial operations, which includes marketing, business development, gas control, customer service, rates and regulatory affairs, and strategy for CPG’s regulated assets. Prior to CPG’s Separation from NiSource Inc. in July 2015, Mr. Chapman served in a similar role as for NiSource’s CPG Business Unit. 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.
Shawn L. Patterson. Mr. Patterson serves as Executive Vice President and Chief Operations Officer, a position he has held since February 2015. Separately, Mr. Patterson serves in the same role at Columbia Pipeline Group, Inc., where he is responsible for capital execution, engineering, operations, integrity, reliability and project management across CPG. Prior to CPG’s Separation from NiSource Inc. in July 2015, Mr. Patterson served as President of Operations and Project Delivery of NiSource’s Columbia Pipeline Group business unit, a position he held since March 2012. Mr. Patterson has held various operational leadership roles with NiSource Electric and Gas utilities for the past 20 years. Prior to his career at Columbia Pipeline Group, Mr. Patterson served as the Chief Operating Officer for NiSource Gas Distribution. He currently serves on the board of the Southern Gas Association and is a member of the Governor’s STEM Council in West Virginia. Mr. Patterson earned a Bachelor of Science degree in Civil Engineering from Rose Hulman Institute of Technology along with a Master of Business Administration from the University of Notre Dame.
G. Stephen Finley. Mr. Finley was appointed to the board of directors in March of 2015. He also serves as a director of Archrock GP LLC, a position he has held since 2006, and Newpark Resources Inc., a position he has held since 2007. He has also served on the board of Microseismic, Inc., from 2012-2014; Total Safety U.S., Inc., from 2006-11; and Ocean Rig, ASA, from 2006-08. Mr. Finley is also a retired Senior Vice President, Finance & Administration and Chief Financial Officer of Baker Hughes, Inc., serving from 1999-2006 in that capacity. Prior to that, he served in various financial and administrative management positions at Baker Hughes from 1982-99. Mr. Finley earned a Bachelor of Science degree in Accounting from Indiana State University. Mr. Finley was nominated to become a director because of his extensive financial, Master Limited Partnership and energy industry experience.

115

Columbia Pipeline Partners LP
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (continued)


Thomas W. Hofmann. Mr. Hofmann was appointed to the board of directors in February 2015. He also currently serves as a director of West Pharmaceutical Services, Inc., a position he has held since October 2007, and also as a director of Northern Tier Energy, LLC, a position he has held since May 2011. Mr. Hofmann served on the board of PVR Partners, L.P. from May 2009 through the March 2014 sale of PVR Partners to Regency Energy Partners LP. Mr. Hofmann is the retired Senior Vice President and Chief Financial Officer of Sunoco, Inc. (oil refining and marketing company), where he served in that capacity from January 2002 until December 2008. Mr. Hofmann earned a Master of Tax degree from Villanova University and a Bachelor of Science degree in Accounting from the University of Delaware. Mr. Hofmann was nominated to become a director because of his substantial knowledge of the industry and his business, leadership and management expertise.
Peggy A. Heeg. Ms. Heeg was appointed to the board of directors in January 2016. Ms. Heeg served as a director of Eagle Rock Energy Partners, L.P. from July 2010 to October 2015. Ms. Heeg is currently a partner at Norton Rose Fulbright L.L.P., an international law firm, and has served on the firm’s Executive Committee. Prior to joining Norton Rose Fulbright, Ms. Heeg held various positions with El Paso Corporation, including serving as Executive Vice President and General Counsel. Ms. Heeg served as attorney and advisor at the Federal Energy Regulatory Commission prior to her time at El Paso.
Director Independence
Our general partner has reviewed the applicable independence standards established by the NYSE and the Exchange Act, and has determined each of Messrs. Hofmann and Finley and Ms. Heeg to be independent under applicable NYSE and Exchange Act rules.
Meeting Attendance and Preparation
Members of our general partner’s board of directors attended at least 90% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
Committees of the Board of Directors
The board of directors of our general partner has established an audit committee and will have the ability to establish a conflicts committee. We do not have a compensation committee, but rather that the board of directors of our general partner approves equity grants to directors and employees. The board may also have such other committees as they determine from time to time.
Audit Committee
The board of directors of our general partner has a standing audit committee that assists the board 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 is given unrestricted access to the audit committee and our management.
The current members of the Audit Committee are Thomas W. Hofmann (chairman), G. Stephen Finley and Peggy A. Heeg, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The board has determined that each member of the audit committee is independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Exchange Act. In making the independence determination, the board considered the requirements of the NYSE. The Audit Committee has adopted a charter, which has been ratified and approved by the board. Mr. Hofmann has been designated by the board of directors as the audit committee’s financial expert meeting the requirements promulgated by the SEC based upon his education and employment experience.
Conflicts Committee
The board of directors of our general partner does not have a standing conflict committee. However, the board has the ability to establish a conflicts committee under our partnership agreement. Any 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 CPG and CEG) or any other matters that the board refers to the committee. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including 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

116

Columbia Pipeline Partners LP
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (continued)


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.
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. All such reporting was done in a timely manner during the year ended December 31, 2015, other than a late Form 3 filing of Mr. Patterson that was filed promptly upon him being made aware of the Section 16(a) filing obligation.
Principles for Corporate Governance and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance. We have also adopted the CPP GP LLC Code of Business Conduct and Ethics and Financial Code of Ethics applicable to persons serving as the general partner’s officers and directors.
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.
Executive Sessions of the Board of Directors
As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing standards, the board of directors of our general partner holds executive sessions on a regular basis without the presence of management. Mr. Hofmann, a non-management director, presides over all executive sessions.
Communications by Unitholders
Unitholders and other interested parties may communicate with any and all members of the board of directors, including non-management directors, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board of directors or any committee of the board of directors at the following address and fax number; Name of the Director(s), c/o Corporate Secretary, Columbia Pipeline Partners, LP, 5151 San Felipe St., Suite 2500, Houston, Texas 77056.
Report of the Audit Committee
The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The audit committee operates under a written charter approved by the board of directors. The charter, among other things, provides that the audit committee has authority to appoint, retain and oversee the independent auditor and is available on the corporate governance section on our website at www.columbiapipelinepartners.com.
In this context, the Audit Committee:
reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;
reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;
received the written disclosures and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte & Touche, LLP’s communications with the audit committee concerning independence from Columbia Pipeline Partners and its subsidiaries, and has discussed with Deloitte & Touche, LLP the firm’s independence;
discussed with Deloitte & Touche, LLP the matters required to be discussed by Statements on Auditing Standards No. 16;

117

Columbia Pipeline Partners LP
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (continued)


discussed with Columbia Pipeline Partner’s internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting;
based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2015, for filing with the SEC; and
approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors.
Audit Committee
Thomas W. Hofmann
G. Stephen Finley
Peggy A. Heeg
February 18, 2016
The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Columbia Pipeline Partners LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.


118

Columbia Pipeline Partners LP
ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis     
Our Chairman and Chief Executive Officer, Robert C. Skaggs, Jr., President, Glen L. Kettering, Executive Vice President and Chief Financial Officer, Stephen P. Smith, Executive Vice President and Chief Commercial Officer, Stanley G. Chapman, III, and Executive Vice President and Chief Operations Officer, Shawn L. Patterson, are our “named executive officers.” These named executive officers are also the named executive officers of CPG. We do not directly employ these named executive officers for managing our business, and we do not have a compensation committee. We are managed by our general partner, and our named executive officers are employees of CPG. Our named executive officers are compensated directly by CPG. All decisions as to the compensation of our named executive officers are and will be determined and approved by the compensation committee of CPG. Therefore, we do not have any policies or programs relating to compensation of our named executive officers, and we make no decisions relating to such compensation. We have no control over this compensation determination process. The named executive officers of CPG participate in CPG’s employee benefit plans and arrangements, including any CPG plans that may be established in the future.
We reimburse our sponsor for the services provided to us by our sponsor’s employees, including our named executive officers. Our reimbursement is governed by our omnibus agreement and will be based on our sponsor’s methodology used for allocating compensation expenses to us. None of the named executive officers of CPG have employment agreements with us or are otherwise specifically compensated by us for their service as a named executive officer of CPG. Other than any awards that may be granted in the future under our long-term incentive plan, the compensation of our named executive officers currently is, and in the future will be, determined and approved by CPG. We are solely responsible for paying the expense associated with any awards granted under our long-term incentive plan.
A full discussion of the policies and programs of the compensation committee of CPG will be set forth in the proxy statement for CPG’s 2016 annual meeting of stockholders which will be available upon its filing on the SEC’s website at www.sec.gov and on CPG’s website at www.cpg.com at the “Investors” tab. CPG’s 2016 Proxy Statement also will be available free of charge from the corporate secretary of our general partner.
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.
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
G. Stephen Finley
Peggy A. Heeg

119

Columbia Pipeline Partners LP
ITEM 11. EXECUTIVE COMPENSATION (continued)

Compensation of Directors
Officers or employees of CPG or its affiliates who also serve as directors of our general partner do not receive additional compensation as such.
Our general partner has 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 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 in an annual amount of $20,000.
In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending board and committee meetings. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.
The following table discloses the cash, equity awards and other compensation earned, paid or awarded, to each of our directors during 2015.
Name
Fees Earned or Paid in Cash
Stock Awards
Option Awards
Non-Equity Incentive Plan Compensation
Change in Pension Value and Nonqualified Deferred Compensation Earnings
All Other Compensation
Total
(a)
($)(b)
($)(c)
($)(d)
($)(e)
($)(f)
($)(g)
($)(h)
Thomas W. Hofmann
72,143

119,922(1)





192,065

G. Stephen Finley
47,903

104,920(2)





152,823

Peggy A. Heeg(3)







(1)Includes 1,119 phantom units granted on February 6, 2015 in connection with Mr. Hofmann's appointment to the board of directors of our general partner and 3,365 phantom units granted on May 12, 2015 in connection with Mr. Hofmann's annual 2015 retainer.
(2)Includes 558 phantom units granted on March 13, 2015 in connection with Mr. Finley's appointment to the board of directors of our general partner and 3,365 phantom units granted on May 12, 2015 in connection with Mr. Finley's annual 2015 retainer.
(3)Ms. Heeg was not a member of the board of directors of our general partner in 2015.

120

Columbia Pipeline Partners LP
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; 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 53,834,784 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
CPG
 

 
%
 
46,811,398

 
100
%
 
50
%
CPP GP LLC
 

 

 

 

 

Robert C. Skaggs, Jr.
 
37,500

 
*

 

 

 

Glen L. Kettering
 
1,300

 
*

 

 

 

Stephen P. Smith
 
37,500

 
*

 

 

 

Robert E. Smith
 
6,100

 
*

 

 

 

Stanley G. Chapman, III
 
5,000

 
*

 

 

 

Shawn L. Patterson
 
1,100

 
*

 

 

 

Thomas W. Hofmann
 
6,119

 
*

 

 

 

G. Stephen Finley
 
15,558

 
*

 

 

 

Peggy A. Heeg
 

 

 

 

 

All executive officers, directors and director nominees as a group (9 persons)
 
110,177

 
0.205
%
 

 
%
 
%
* Less than 1%

121

Columbia Pipeline Partners LP
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (continued)


The following table sets forth as of January 30, 2016, the number of shares of common stock of CPG 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.
 
724,444

(1) 
*

Glen L. Kettering
 
140,686

(2) 
*

Stephen P. Smith
 
185,790

(3) 
*

Robert E. Smith
 
21,521

(4) 
*

Stanley G. Chapman, III
 
18,019

(5) 
*

Shawn L. Patterson
 
36,696

(6) 
*

Thomas W. Hofmann
 

 

G. Stephen Finley
 

 

Peggy A. Heeg
 

 

All executive officers, directors and director nominees as a group (9 persons)
 
1,127,156

 
0.282
%
* Less than 1%
(1) Does not include 333,719 restricted stock units that are subject to vesting in 2016.
(2) Does not include 55,620 restricted stock units that are subject to vesting in 2016.
(3) Does not include 139,050 restricted stock units that are subject to vesting in 2016.
(4) Does not include 13,905 restricted stock units that are subject to vesting in 2016.
(5) Does not include 84,542 restricted stock units that are subject to vesting in 2016.
(6) Does not include 22,247 restricted stock units that are subject to vesting in 2016.
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.

122

Columbia Pipeline Partners LP
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of February 10, 2016, 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 CPG 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.

123

Columbia Pipeline Partners LP
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (continued)


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.
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.”

124

Columbia Pipeline Partners LP
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (continued)


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 further provides 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.
Separation Covenant. Under the omnibus agreement, we have agreed to refrain for two years from the date of the omnibus agreement from taking any actions that could cause CPG to violate its covenants under the tax sharing agreement that CPG entered into with NiSource in connection with the Separation. In addition, we have agreed 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 CPG nor any of its affiliates is restricted, under either our partnership agreement or the omnibus agreement, from competing with us. NiSource and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or contract those assets.
Indemnification. Under the omnibus agreement, CEG will indemnify us for three years from the date of the omnibus agreement against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before the date of the omnibus agreement. The maximum liability of CEG for this indemnification obligation will not exceed $15 million and CEG will not have any obligation under this indemnification obligation until our aggregate losses exceed $250,000. CEG will not have any 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 date of the omnibus agreement. We have agreed to indemnify CEG against environmental liabilities related to our assets to the extent CEG is not required to indemnify us.
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.

125

Columbia Pipeline Partners LP
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (continued)


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.
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;

126

Columbia Pipeline Partners LP
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (continued)


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
The board of directors of our general partner has 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.
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.
Board Leadership and Risk Oversight
The board of directors of our general partner is currently led by our Chairman, Mr. Skaggs. In exercising its duties to our unitholders, our board members should not be conflicted in any way and we have procedures that are specified in our partnership agreement to address potential conflicts, which include referring transactions that present a conflict to a conflicts committee. We believe that this board leadership structure is appropriate in maximizing the effectiveness of our board oversight and in providing perspective to our business.
The board has responsibility for oversight of our risk management process and receives regular reports from our executives and from CPG regarding the risks faced in our business. The board exercises its risk oversight responsibilities through the audit committee, with respect to financial reporting and compliance risks. In addition, the Compensation Committee of the CPG board of directors provides oversight with respect to risks that may be created by our compensation programs. CPG management has undertaken, and the Compensation Committee has reviewed, an evaluation of the incentives to its employees to take risk that are created by its compensation programs. Based upon that evaluation, CPG has concluded that its compensation programs do not create risks that are reasonably likely to result in a material adverse affect on the Company.
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.


127

Columbia Pipeline Partners LP
ITEM 14. PRINCIPAL ACCOUNTING 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 years ended December 31, 2015 and 2014.
(in millions)
 
2015
2014
 
 
 
 
Audit Fees(1)(2)
 
$
2.5

$
1.7

Audit-Related Fees(3)
 


Tax Fees(4)
 


All Other Fees(5)
 


Total
 
$
2.5

$
1.7

(1) Audit fees for the year ended December 31, 2015 relate to professional services rendered in connection with the audit of our annual financial statements on our Form 10-K and review of financial statements included in our Form 10-Q, 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 fees for the year ended December 31, 2014 relate to professional services rendered in connection with the audit of our 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.
(3) 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.
(4) Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.
(5) 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 services reported in the audit, audit-related, tax, and all other fees categories for periods prior to the Audit Committee formation.

128

Columbia Pipeline Partners LP
PART IV
ITEM 15. EXHIBITS, 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."
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 a (†).
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.

129


Columbia Pipeline Partners LP



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.
 
 
 
Columbia Pipeline Partners LP
 
 
(Registrant)
 
 
 
 
By:
CPP GP LLC, its general partner
 
 
 
Date:                 February 18, 2016                
By:
/s/                          ROBERT C. SKAGGS, JR.
 
 
Robert C. Skaggs, Jr.
 
 
Chief Executive Officer

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
Date: February 18, 2016
 
 
 
Robert C. Skaggs, Jr.
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
 
 
/s/
STEPHEN P. SMITH
 
Executive Vice President, Director and
Date: February 18, 2016
 
 
 
Stephen P. Smith
 
Chief Financial Officer
(Principal Financial Officer)
 
 
 
 
 
 
 
 
 
 
/s/
JON D. VEURINK
 
Senior Vice President and
Date: February 18, 2016
 
 
 
Jon D. Veurink
 
Chief Accounting Officer
(Principal Accounting Officer)
 
 
 
 
 
 
 
 
 
 
/s/
GLEN L. KETTERING
 
Director and President
Date: February 18, 2016
 
 
 
Glen L. Kettering
 
 
 
 
 
 
 
 
 
 
 
 
/s/
ROBERT E. SMITH
 
Senior Vice President, Director and
Date: February 18, 2016
 
 
 
Robert E. Smith
 
General Counsel
 
 
 
 
 
 
 
 
 
 
/s/
STANLEY G. CHAPMAN, III
 
Executive Vice President, Director and
Date: February 18, 2016
 
 
 
Stanley G. Chapman, III
 
Chief Commercial Officer
 
 
 
 
 
 
 
 
 
 
/s/
G. STEPHEN FINLEY
 
Director
Date: February 18, 2016
 
 
 
G. Stephen Finley
 
 
 
 
 
 
 
 
 
 
 
 
/s/
PEGGY A. HEEG
 
Director
Date: February 18, 2016
 
 
 
Peggy A. Heeg
 
 
 
 
 
 
 
 
 
 
 
 
/s/
THOMAS W. HOFMANN
 
Director
Date: February 18, 2016
 
 
 
Thomas W. Hofmann
 
 
 
 
 
 
 
 
 
 

130


Columbia Pipeline Partners LP



EXHIBIT INDEX
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with (†) are management contracts or compensatory plan or agreement of Columbia Pipeline Partners LP.
 
 
(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)
Second Amended and Restated Agreement of Limited Partnership of Columbia Pipeline Partners LP, dated as of June 30, 2015 (Incorporated by reference to Exhibit 3.3 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-36835) filed on August 3, 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).
 
 
(4.2)
Indenture, dated as of May 22, 2015, by and among CPG, the Guarantors and U.S. Bank National Association, as Trustee, governing the Notes (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 2015).
 
 
(4.3)
Registration Rights Agreement, dated as of May 22, 2015, by and among CPG, the Guarantors and the Initial Purchasers, relating to the Notes (Incorporated by reference to Exhibit 4.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 2015).
 
 
(4.4)
Form of 2.45% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 2015).
 
 
(4.5)
Form of 3.30% Senior Note due 2020 (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 2015).
 
 
(4.6)
Form of 4.50% Senior Note due 2025 (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 2015 4.6 Form of 5.80% Senior Note due 2045 (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36835) filed on May 22, 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)
Amended and Restated System Money Pool Agreement, dated as of July 1, 2015, by and among Columbia Pipeline Group, Inc., Columbia Pipeline Group Services Company, as administrative agent, and the direct and indirect subsidiaries of Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.1 of the Partnership’s Quarterly Report on Form 10-Q (File No. 333-198990) filed on November 3, 2015)
 
 
(10.6)
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).
 
 

131


Columbia Pipeline Partners LP



(10.7)
Trademark License Agreement, dated as of February 11, 2015, by and between NiSource Corporate Services Company and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-K (File No. 001-36835) filed on February 18, 2015).
 
 
(10.8)
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).
 
 
(10.11)
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).
 
 
(21.1)*
List of Subsidiaries of Columbia Pipeline Partners LP.
 
 
(23.1)*
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.
 
 
(32.2)**
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.
 
 
(101.INS)*
XBRL Instance Document
 
 
(101.SCH)*
XBRL Schema Document
 
 
(101.CAL)*
XBRL Calculation Linkbase Document
 
 
(101.LAB)*
XBRL Labels Linkbase Document
 
 
(101.PRE)*
XBRL Presentation Linkbase Document
 
 
(101.DEF)*
XBRL Definition Linkbase Document
 
 


132