Annual Report (10-k)

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, 2016

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 001-36838

Columbia Pipeline Group, Inc.

(Exact name of registrant as specified in its charter)

Delaware		47-1982552
(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)

[phone]

(Registrant’s telephone number, including area code)

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

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

I ndicate 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 þ    No ¨

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 þ		Accelerated filer ¨
Non-accelerated filer ¨		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

On July 1, 2016, Columbia Pipeline Group, Inc. was acquired (see Note 1 of Notes to Consolidated and Combined Financial Statements), as a result of which 100% of its equity is currently held by a single stockholder and the registrant deregistered its equity under the Securities Exchange Act of 1934.

This Annual Report on Form 10-K filed by Columbia Pipeline Group, Inc. meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore being filed with the reduced disclosure format allowed under that General Instruction.

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CONTENTS

 

		Page No.
Defined Terms		3
Part I
Items 1 and 2.	Business and Properties	8
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	27
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	96
Item 9A.	Controls and Procedures	96
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	97
Item 11.	Executive Compensation	97
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	97
Item 13.	Certain Relationships and Related Transactions, and Director Independence	97
Item 14.	Principal Accounting Fees and Services	97
Part IV
Item 15.	Exhibits, Financial Statement Schedules	98
Signatures		99
Exhibit Index		100

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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 Group, Inc.
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
Columbia Remainder Corporation	Columbia Remainder Corporation
CPGSC	Columbia Pipeline Group Services Company
CPP GP LLC	CPP GP LLC
CPPL	Columbia Pipeline Partners LP
Crossroads	Crossroads Pipeline 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
TCPL	TransCanada PipeLines Limited
TransCanada	TransCanada Corporation
US Parent	TransCanada PipeLine USA Ltd.
Abbreviations and Definitions
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 in service
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
CPPL Merger	Effective February 17, 2017, Pony Merger Sub LLC merged with and into CPPL, with CPPL surviving. Following the CPPL Merger, MLP GP remains an indirect wholly owned subsidiary of CPG and the sole general partner of CPPL, and CPG and CEG are the only limited partners of CPPL.
DOT	Department of Transportation
Dth/d	Dekatherms per day
EIA	U.S. Energy Information Administration
end-user markets	The ultimate users and consumers of transported energy products
EPA	United States Environmental Protection Agency

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DEFINED TERMS (continued)
EPS	Earnings per share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
Hilcorp	Hilcorp Energy Company
HP	Horsepower
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
LIBOR	London Interbank Offered Rate
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
Merger	Effective July 1, 2016, Taurus Merger Sub Inc. was merged with and into Columbia Pipeline Group, Inc. with Columbia Pipeline Group, Inc. surviving the merger as an indirect, wholly owned subsidiary of TransCanada Corporation.
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)
OPEB	Other postretirement benefits
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
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
SEC	Securities and Exchange Commission
shale gas	Natural gas produced from organic (black) shale formations
Tcf	One trillion cubic feet

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DEFINED TERMS (continued)
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.

 

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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;

•	restrictions in our existing and any future credit facilities;

•	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, including litigation relating to the Merger and the CPPL Merger;

•	the occurrence of any event, change or other circumstance in connection with the recent Merger and the CPPL Merger;

•	risks related to the disruption of management’s attention from our ongoing business operations due to the Merger and the CPPL Merger;

•	risks associated with the loss and ongoing replacement of key personnel due to the recent Merger;

•	risks relating to unanticipated costs of integration in connection with the Merger, including operating costs, customer loss or business disruption being greater than expected;

•	risks relating to the difficulties in integrating businesses and management of CPG and TransCanada; and

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•	certain factors discussed elsewhere in this report.

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

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PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Unless the context otherwise requires, references in this Annual Report on Form 10-K (this "Form 10-K") to “we,” “us,” “our,” the “Company” and “CPG” refer to Columbia Pipeline Group, Inc., a Delaware corporation, and its consolidated subsidiaries including CEG and CPPL.

Organizational History

We are a growth-oriented Delaware corporation formed by NiSource on September 26, 2014 to own, operate and develop a portfolio of pipelines, storage and related midstream assets. On July 1, 2015, NiSource distributed, pursuant to an effective registration statement on Form 10, 317.6 million shares, one share of CPG common stock for every one share of NiSource common stock held by NiSource stockholders on the record date. As of July 1, 2015, CPG was an independent, publicly traded company, and NiSource does not retain any ownership interest in CPG (the "Separation"). CPG's common stock began trading "regular-way" under the ticker symbol "CPGX" on the NYSE on July 2, 2015.

On March 17, 2016, CPG entered into an Agreement and Plan of Merger (the "Merger Agreement"), among CPG, TCPL, US Parent, Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent ("Merger Sub"), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016, Merger Sub was merged with and into CPG (the "Merger") with CPG surviving the Merger as an indirect wholly owned subsidiary of TransCanada.

On July 1, 2016, TransCanada closed the acquisition of CPG valued at $13.0 billion, comprised of a purchase price of approximately $10.3 billion and CPG debt of approximately $2.7 billion. CPG became an indirect, wholly owned subsidiary of TransCanada as a result of the Merger. Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of CPG common stock, par value $0.01 per share, was canceled and converted into the right to receive $25.50 per share in cash, without interest. Upon completion of the transaction, TransCanada owns the general partner of CPPL, all of CPPL’s incentive distribution rights and all of CPPL's subordinated units, which represent a 46.5% limited partnership interest in CPPL. As a result, CPPL is now effectively managed by TransCanada.

We own 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. For the year ended December 31, 2016, 94.8% of our revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2016, these contracts had a weighted average remaining contract life of 4.4 years. We own these assets through Columbia OpCo, a partnership between our wholly owned subsidiary CEG and CPPL.

Through our wholly owned subsidiary CEG, we own the general partner of CPPL, all of CPPL’s incentive distribution rights and all of CPPL’s subordinated units, which, in the aggregate, represent a 46.5% limited partner interest in CPPL. CPPL completed its initial public offering on February 11, 2015, selling 53.5% of its limited partner interests.

CPPL Merger . On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.

The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the merger agreement and transactions contemplated by the merger agreement and determined that the merger agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the merger agreement and the merger transactions. The GP Board resolved that the merger agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the merger agreement and the merger transactions at the special meeting of the unitholders.

On February 16, 2017, the CPPL unaffiliated unitholders voted to approve the CPPL Merger. On February 17, 2017, CPG closed the transaction to acquire all outstanding publicly held common units valued at approximately $915.2 million. CPPL unaffiliated unitholders also received a regular quarterly distribution of $0.1975 per common unit and a pro-rated distribution for the period prior to the closing date. As a result of the CPPL Merger, CPPL became a wholly owned subsidiary of CPG.

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ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)

Business Segment

Our operations comprise one reportable segment containing our portfolio of pipelines, storage and related midstream assets. Please see Note 21, “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 . 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 11,255 miles of natural gas transmission pipeline. It has a transportation capacity of approximately 12 MMDth/d, transports an average of approximately 4.8 MMDth/d and serves communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission owns and leases approximately 819,400 acres of underground storage, 3,417 storage wells, which includes 35 storage fields in four states with approximately 630 MMDth in total operational capacity, with approximately 290 MMDth of working gas capacity.

Columbia Gulf .  The Columbia Gulf pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of 3,341 miles of natural gas transmission pipeline. The system offers shippers access to two actively traded market hubs—the Columbia Gulf Mainline Pool and the Columbia Gulf Onshore Pool. In addition, Columbia Gulf interconnects with the Henry Hub in South Louisiana and the Columbia Gas Transmission Pool near Leach, Kentucky. Through its 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 1.3 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 50% 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. A third party, Piedmont Natural Gas Company, Inc., owns the remaining 50% ownership interest 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 148 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and also owns a 47.0% 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.

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ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)

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.

Regulation

The Company is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.

FERC has comprehensive jurisdiction over the Company.  In accordance with the Natural Gas Act of 1938, FERC’s jurisdiction over natural gas companies encompasses, among other things, the acquisition, operation and disposition of assets and facilities, the services provided and rates charged.

FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities.  The Company holds certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce.

The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

For additional information regarding the Company’s regulation and rates, see “Item 1. Business - Environmental”, “Item 1A.  Risk Factors.”

Pipeline Safety

The Company is also subject to federal pipeline safety statutes, such as the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002 (the "PSI Act"), the Pipeline Inspection, Protection, and Enforcement Act of 2006 (the PIPES Act, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the "2011 Pipeline Safety Act"), and, Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act or 2016 (the "2016 Pipeline Safety Act"), which regulate the safety of natural gas pipelines. These statutes, and the associated regulations promulgated and administered under these acts are administered by PHMSA. Recently, PHMSA has promulgated both Interim Final Rules and Proposed Rules that, taken in its entirety, 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. We are closely monitoring and providing comment to PHMSA and industry groups regarding the proposed rules but at this time cannot predict the impact of any final rulemaking.

For additional information regarding the Company’s regulation and rates, see “Item 1A.  Risk Factors.”

Environmental

The Company is subject to federal, state and local laws and regulations regarding water quality, hazardous and nonhazardous waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental laws, regulations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements may expose the Company to significant liabilities including the assessment of fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations and, historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements. For additional information concerning the impact of environmental regulation on the Company, see “Item 1A. Risk Factors” and Note 17 to our consolidated and combined financial statements.

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

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ITEMS 1 AND 2. BUSINESS AND PROPERTIES (continued)

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 12% of our total operating revenues for the year ended December 31, 2016 . No other customer accounted for greater than 10% of total operating revenue. Please see Note 23, “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

As of December 31, 2016, we had approximately 1,782 active employees. Of these 1,782 employees, 258 are covered by collective bargaining agreements, 51 of which expire in 2017.

Additional Information

We were formed on September 26, 2014 as a Delaware corporation. 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.columbiapipelinegroup.com . These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.

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ITEM 1A. RISK FACTORS

RISK FACTORS

Our business, results of operations, cash flows and financial condition are subject to a number of risks and uncertainties. You should carefully consider the risks and uncertainties described below, together with all of the other information in this Form 10-K. The risks and uncertainties we face are not limited to those described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially adversely affect our business, results of operations, cash flows and financial condition. This Form 10-K also contains forward-looking statements that involve risks and uncertainties. You should carefully read the section entitled “Cautionary Note Concerning Forward-Looking Statements” on page 6 of this Form 10-K.

If any of the following risks were to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, the value of the Notes could decline and you could lose all or part of your investment.

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium (if any), and interest on our indebtedness, including the notes.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness, including the notes. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments and the indenture governing the notes may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

We may be subject to class action lawsuits relating to the CPPL Merger, which could materially adversely affect our business, financial condition and operating results.

Our directors and officers may be subject to class action lawsuits relating to the CPPL Merger and other additional lawsuits that may be filed. Such litigation is very common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.

One of the conditions to consummating the CPPL Merger is that no injunction or other order prohibiting or otherwise preventing the consummation of the CPPL Merger transactions shall have been issued by any court or governmental entity of competent jurisdiction in the United States. Consequently, if any lawsuit is filed challenging the CPPL Merger and is successful in obtaining an injunction preventing the parties to the CPPL Merger Agreement from consummating the CPPL Merger, such injunction may prevent the CPPL Merger from being completed in the expected timeframe, or at all.

Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations.

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

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

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

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

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

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

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

•	an inability to successfully integrate 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.

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 and growth plans.

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 and growth plans.

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.

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 from such project 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

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to unregulated exploration and production and gathering activities in new production areas, including the Marcellus shale area. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

A substantial portion of our 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 our 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 our revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either us 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 and results of operations.

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results.

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. 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.

We receive cash from royalty payments 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.

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We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:

•	the timing and amount of capital expenditures;

•	the timing of initiating the drilling and recompleting of wells;

•	the extent of operating costs;

•	selection of technology and drilling and completion methods; and

•	the rate of production of reserves, if any.

If the royalty payments we receive from our sublessees are reduced, our business and financial condition could be adversely affected.

Our revenues from CEVCO royalty interests will decrease if production on our subleased production rights declines, which could adversely affect our business and operation results.

The amount of the royalty payments we receive on our subleased 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 2016 and 2015, 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 our business and operation results.

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

Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade pipelines and other facilities. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; and incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates polychlorinated biphenyls (“PCBs”) at specific gas transmission facilities pursuant to a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs ceased on January 31, 2015. As of December 31, 2016, Columbia Gas Transmission had remaining liabilities of $1.5 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, revisions to the National Ambient Air Quality Standard (“NAAQS”) for ozone to may result in the addition of non-attainment designations in additional counties in which our pipeline systems operates, which could result in additional permitting delays, capital expenditures and operating costs to our and our customers’ operations. 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

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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.

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 investigatory, remedial or corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the permitting or performance or expansion of projects and the issuance of injunctions limiting or preventing some or all of our operations in a particular area. In addition, strict joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have a material adverse effect on our business, results of operations and financial condition.

Current and future emissions regulation legislation or regulations restricting emissions of GHG could result in increased operating costs.

There have been a number of legislative initiatives to regulate GHG emissions; however, substantial uncertainty exists regarding the impact of new and proposed GHG laws and regulations. Moreover, implementation of GHG regulations is the subject of significant litigation which has created uncertainty in compliance requirements with both the regulatory agencies and industry. Recent federal rulemakings have focused on the emission of methane. For example, in June 2016, the EPA published New Source Performance Standards, known as Subpart Quad OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from existing facilities and operators in the oil and natural gas industry that the agency may potentially use to develop guidelines that the states must consider in developing their own rules for regulating sources within their borders. EPA has indicated that this information may also be used to develop standards for certain kinds of new and modified equipment and facilities not currently covered under Subpart OOOOa. Furthermore, the EPA has passed a rule, known as the Clean Power Plan, to limit GHGs from power plants but in February 2016, the U.S. Supreme Court stayed this rule while it is being challenged in the federal D.C. Circuit Court of Appeals. If this rule survives legal challenge, then depending on the methods used to implement this rule, it could increase demand for the oil and natural gas our customers produce or increase the cost of electricity for our operations. While we do not believe that compliance with the new Subpart OOOOa regulations will have a material adverse effect on our operations, we cannot estimate the effect of proposed and final regulations, and industry litigation related to the control of GHG emissions on our future financial position, results of operations or cash flow. However, such legislation, regulation and litigation could materially increase their operating costs, including their cost of environmental compliance. Given the uncertainty of policy and regulatory schemes, the future effects on our pipelines cannot be predicted.

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

•	perform ongoing assessments of pipeline integrity;

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

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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In addition, on March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, operating pressure limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines.

We continue to evaluate the impact of many PHMSA initiatives and mandates. At this time, we cannot predict the ultimate impact of this legislation on our operations; however, the adoption of any new legislation or regulations regarding increased pipeline safety could cause us to incur increased capital and operating costs, which costs could be significant.

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.

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.

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 Natural Gas Pipeline Safety Act (“NGPSA”) was amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed 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 natural gas transmission pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the "2016 Pipeline Safety Act”) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 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.

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

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adverse effect on our business, results of operations and financial condition. In February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators. The bulletin recommended 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 advised 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 directed compliance with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommended the voluntary implementation of certain industry-recognized recommended practices for natural gas storage facilities. More recently, in December 2016, PHMSA issued an interim final rule that revises federal pipeline safety regulations to address safety issues related to downhole facilities, including well integrity, wellbore tubing, and casing. Pursuant to the interim rule, PHMSA incorporates by reference into its rules the American Petroleum Institute’s Recommended Practices for the design and operation of solution-mined salt caverns used for natural gas storage, and functional integrity of natural gas storage in depleted hydrocarbon reservoirs and aquifer reservoirs. PHMSA indicated when it issued the interim final rule that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. At this time, we cannot predict the impact of any future regulatory actions in this area.

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. FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.  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.

Compliance with these requirements can be costly and burdensome and 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.

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.

On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy on income tax allowance permits an income tax allowance in cost-based rates proposed by such pipeline companies

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to the extent the pipeline companies can show an actual or potential income tax liability to be paid on income generated by the companies’ FERC-regulated assets. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, a case involving an oil pipeline organized as a partnership. In that case, the D.C. Circuit determined that FERC had not justified its conclusion that there was no double recovery of taxes by the oil pipeline when FERC granted the pipeline a tax allowance in its cost-based rates and at the same time set a return on equity underlying the cost-based rates on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on income tax allowances for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipeline companies could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates.

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

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

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

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

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 approximately $1.2 million 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

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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.

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

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

•	aging infrastructure, mechanical or other performance problems;

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

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

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

•	operator error;

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

•	explosions and blowouts.

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

Our existing indebtedness and debt that we incur in the future may limit our flexibility to obtain additional financing and to pursue other business opportunities.

As of December 31, 2016, we and our subsidiaries had $2.75 billion in outstanding indebtedness, comprised of our senior notes (the “Notes”).

Our existing and future level of debt, could have important consequences to us, including the following:

•	our 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 have available for operations will be reduced by that portion of our 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, including the notes, 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 facilities 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 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.

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ITEM 1A. RISK FACTORS (continued)

Deterioration in our credit profile could increase our costs of borrowing money, adversely affect our business relationships and limit our access to the capital markets and commercial credit.

We currently have an investment grade credit rating from Standard & Poor’s Rating Service (S&P), Moody’s Investor Service (Moody's) and Fitch Ratings. Our parent, TCPL, currently has an investment grade rating from S&P, Moody's and DBRS Limited. However, our credit ratings and those of our parent could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our or our parent's rating below investment grade, our borrowing costs would increase and our funding sources could decrease. In addition, a failure to maintain an investment grade credit rating could affect our business relationships with suppliers and operating partners. A downgrade of our or our parent's credit ratings could also adversely affect the availability and cost of capital needed to fund the growth investments that are a central element of our long-term business strategy.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues 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 United States 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 and financial condition.

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

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

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.

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ITEM 1A. RISK FACTORS (continued)

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.

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 commercial paper program and 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.

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

We may be unable to make acquisitions from third parties as an alternative avenue to growth. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our earnings. 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 bondholders 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 United States, 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.

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ITEM 1A. RISK FACTORS (continued)

A failure in our computer systems or a cyber-attack on any of our facilities or any third parties’ facilities upon which we rely may adversely affect our ability to operate.

We rely on technology to run our businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of our business, including the operation of our gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our businesses and could result in a financial loss and possibly do harm to our reputation.

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

Sustained extreme weather conditions and climate change may negatively impact our operations.

We conduct our 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 our infrastructure may reveal weaknesses in our systems not previously known to us or otherwise present various operational challenges across all business segments. Although we make every effort to plan for weather-related contingencies, adverse weather may affect our ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. We endeavor 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 our business in many ways, including increasing the costs we incur in providing our products and services, impacting the demand for and consumption of our products and services (due to changes in both costs and weather patterns), and affecting the economic health of the regions in which we operate.

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 our customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. Our inability to renew or replace our current contracts as they expire and respond appropriately to changing market conditions could materially impact our financial results and cash flows.

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

Our assets are insured for certain property damage, business interruption, and third-party liabilities, which includes certain pollution liabilities. All of the insurance policies relating to our assets and operations are subject to policy limits and deductibles including the waiting period under business interruption insurance. We do 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. The occurrence of an event that is not fully covered by insurance, the unavailability of insurance coverage, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our 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 our assets and operations. If significant changes in the number or financial solvency of insurance companies for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost.

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ITEM 1A. RISK FACTORS (continued)

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 interest rates. As of December 31, 2016, we had $2.75 billion in outstanding indebtedness, none of which is 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 could result in additional funding and impact earnings.

The performance of capital markets affects the value of assets held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. These assets are invested in financial instruments (i.e. equities and fixed income securities) subject to market fluctuations which may yield uncertain returns, including falling below our projected rates of return. A decline in the market value of assets may increase our funding requirements. Additionally, changes in interest rates are inversely related to liabilities. In particular, as interest rates decrease, liabilities increase, potentially increasing funding requirements. Other factors that could impact funding requirements include changes in government regulations and participant demographics (i.e. increased pace of retirements or changes in life expectancy assumptions). Ultimately, higher funding requirements and 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 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.

If the Distribution were to fail to qualify as tax-free for U.S. federal income tax purposes, then NiSource could be subject to significant tax liability, and we could be required to indemnify NiSource for all or a portion of such liability.

NiSource received an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution. NiSource’s receipt of the opinion was a condition to the completion of the Distribution. The opinion was based upon various factual representations and assumptions, as well as certain undertakings made by us and NiSource. If any of those factual representations or assumptions are untrue or incomplete in any material respect, any undertaking is not complied with, or the facts upon which the opinion was based are materially different from the facts at the time of the Distribution, the Distribution may not qualify for tax-free treatment. Opinions of counsel are not binding on the Internal Revenue Service (“IRS”) or the courts. As a result, the conclusions expressed in an opinion of counsel could be challenged by the IRS, and if the IRS prevails in such challenge, the tax consequences to you could be materially less favorable.

If the Distribution ultimately is determined to be taxable, the Distribution could be treated as a taxable dividend to stockholders who received our stock in the Distribution or cause them to recognize taxable capital gain for U.S. federal income tax purposes. Those prior stockholders could incur significant U.S. federal income tax liabilities. In addition, NiSource would recognize gain in an amount equal to the excess of the fair market value of the shares of our common stock distributed to NiSource stockholders on the Distribution Date over NiSource’s tax basis in such shares as of such date.

In addition, under the terms of the Tax Allocation Agreement that we entered into in connection with the Distribution (as described under Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined

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ITEM 1A. RISK FACTORS (continued)

Financial Statements” of this Form 10-K), in the event that the Distribution were determined to be taxable as the result of actions taken after the Distribution by us or any of our subsidiaries, we would be responsible for all taxes imposed on NiSource as a result thereof. In addition, in the event the Distribution were determined to be taxable and neither we nor NiSource were at fault, we would be responsible for a portion of the taxes imposed on NiSource as a result of such determination. Any such tax amounts could be significant.

We might not be able to engage in desirable strategic transactions and equity issuances following the Distribution because of certain restrictions relating to requirements for tax-free distributions.

Our ability to engage in significant transactions could be limited or restricted after the Distribution in order to preserve, for U.S. federal income tax purposes, the tax-free nature of the Distribution by NiSource. We have agreed to take reasonable action or reasonably refrain from taking action to ensure that the Separation qualifies for tax-free status under Section 355 of the Code. We also have agreed to various other covenants in the Tax.

Allocation Agreement intended to ensure the tax-free status of the Distribution. These covenants may restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. Any acquisitions or issuances of our stock or NiSource’s stock (or any successor thereto) within two years after the Distribution are generally presumed to be related to the Separation, although we or NiSource may be able to rebut that presumption.

To preserve the tax-free treatment to NiSource of the Distribution, under the Tax Allocation Agreement that we have entered into with NiSource, for the two-year period following the Distribution, without obtaining the consent of NiSource, an unqualified opinion of a nationally recognized law firm or a private letter ruling from the IRS, we may be prohibited from:

•	approving or allowing issuance of our common stock, except in certain limited circumstances,

•	approving or allowing an issuance or sale of equity securities in Columbia OpCo that results in our owning less than 55% of the outstanding equity securities of Columbia OpCo,

•	redeeming equity securities,

•	selling or otherwise disposing of the ownership of the general partner of CPPL or of a specified percentage of our assets or the assets of certain of our subsidiaries, or

•	engaging in certain other transactions that could jeopardize the tax-free status of the Distribution.

  These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business. Moreover, the Tax Allocation Agreement also provides that we are responsible for any taxes imposed on NiSource or any of its affiliates as a result of the failure of the Distribution to qualify for favorable treatment under the Code if such failure is attributable to certain actions taken at any time (even outside the two-year period described above) after the Distribution by or in respect of us or any of our subsidiaries.

We will not have complete control over our tax decisions and could be liable for income taxes owed by NiSource.

For any tax periods (or portion thereof) in which NiSource owned at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries were included in NiSource’s consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of NiSource or one or more of its subsidiaries for U.S. state or local income tax purposes. Moreover, notwithstanding the Tax Allocation Agreement, U.S. federal law provides that each member of a federal consolidated group is liable for the group’s entire federal income tax obligation. Thus, to the extent NiSource or other members of NiSource’s consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of NiSource’s consolidated group. Similar principles may apply for non-U.S., state or local income tax purposes where we filed combined, consolidated or unitary returns with NiSource or its subsidiaries for non-U.S., state or local income tax purposes.

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ITEM 1A. RISK FACTORS (continued)

The indemnification arrangements we entered into with NiSource in connection with the Separation may require us to make certain indemnification payments to NiSource to satisfy our indemnification obligations and any indemnification payments we receive from NiSource may not be sufficient to cover the full amount of losses for which NiSource has agreed to indemnify us.

Pursuant to the Separation and Distribution Agreement and certain other agreements, NiSource has agreed to indemnify us from certain liabilities and we have agreed to indemnify NiSource for certain liabilities, as discussed further in Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements.

A court could deem the Distribution to be a fraudulent conveyance and void the transaction or impose substantial liabilities upon us.

A court could deem the Distribution or certain internal restructuring transactions undertaken by NiSource in connection with the Separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our results of operations, cash flows and financial condition. Among other things, the court could require our stockholders to return to NiSource, for the benefit of its creditors, some or all of the shares of our common stock issued in the Distribution, or require us to fund liabilities of other companies involved in the restructuring transaction. Whether a transaction is a fraudulent conveyance or transfer under applicable state law may vary depending upon the jurisdiction whose law is being applied.

Our agreements with NiSource relating to the Separation require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.

We negotiated all of our agreements with NiSource relating to the Separation as a wholly owned subsidiary of NiSource. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the Separation and Distribution Agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the Tax Allocation Agreement as described further in Refer to Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements) related to our business, and have agreed to indemnify NiSource for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between NiSource and us may not reflect the allocation that would have been reached between two unaffiliated parties. In addition, we have limited remedies under the Separation and Distribution Agreement. See Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements for a description of these obligations and the allocation of liabilities between NiSource and us.

Third parties may seek to hold us responsible for liabilities of NiSource that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of NiSource. Under the agreements we entered into with NiSource, NiSource has agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from NiSource.

Our prior and continuing relationship with NiSource exposes us to risks attributable to businesses of NiSource.

Under the Separation and Distribution Agreement we entered into with NiSource, NiSource is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of NiSource that are incurred through a breach of the Separation and Distribution Agreement or any ancillary agreement by NiSource or its affiliates other than us or our post-Separation affiliates, or losses that are attributable to NiSource in connection with the Separation or are not expressly assumed by us under our agreements with NiSource. Immediately following the Separation, any claims made against us that are properly attributable to NiSource in accordance with these arrangements would require us to exercise our rights under our agreements with NiSource to obtain payment from them. We are exposed to the risk that, in these circumstances, NiSource cannot, or will not, make the required payment.

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ITEM 1A. RISK FACTORS (continued)

If in the future we cease to manage and control CPPL through our direct and indirect ownership of the general partner interests in CPPL, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control CPPL and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 3. LEGAL PROCEEDINGS

Litigation Relating to the Merger

On March 30, 2016, two purported stockholders of CPG filed an action challenging the Merger on behalf of a putative class of CPG stockholders in the Court of Chancery of the State of Delaware, captioned Vann v. Columbia Pipeline Group, Inc. , et al . The action names as defendants CPG, the members of the Board, TCPL, US Parent, Merger Sub and TransCanada. On April 7, 2016, a second, substantially identical action was filed in the same court on behalf of the same putative class, captioned Baldino v. Skaggs, Jr., et al. , and naming as defendants only the members of the Board. On May 25, 2016, the Delaware Court of Chancery entered an order that, among other things, consolidated the actions into a single action, captioned as In re Columbia Pipeline Group, Inc. Stockholder Litigation , and appointed the Vann plaintiffs as lead plaintiffs and the Vann plaintiffs’ counsel as lead counsel. The Vann plaintiffs’ amended complaint, filed May 12, 2016, alleges that members of the CPG Board breached their fiduciary duties by, among other things, agreeing to the Merger following an inadequate sale process and at an unfair price, and because the sale process purportedly was affected by conflicts of interest on the part of the Board, the management of CPG and/or CPG’s largest stockholder as a result of their substantial stockholdings in CPG, and on the part of one of CPG’s financial advisors as a result of its alleged holdings in TransCanada stock. The amended complaint also alleges that the preliminary proxy filed in respect of the Merger omits or misstates various facts concerning, among other things, the sale process and the financial analyses performed by CPG’s financial advisors. The amended complaint purports to seek injunctive and other equitable relief regarding the Merger. On July 5, 2016, the defendants filed a motion to dismiss the action and a motion to stay discovery pending resolution of the motion to dismiss. On July 18, 2016, Vice Chancellor Laster entered the briefing schedule deferring briefing on the motion to dismiss until the motion to stay is resolved. On September 6, 2016, Vice Chancellor Laster granted TransCanada and CPG’s motion to stay discovery while the motion to dismiss was pending. On October 6, 2016, the Vann plaintiffs filed an amended claim which removed all TransCanada parties, limiting the action to the CPG Board and CFO. Its revised claim alleges that the Board and officers entered into a secret scheme to benefit directors and insiders via change in control benefits and payments originating when NiSource first spun off the Columbia assets. They continue their allegations that conflict of interest tainted the acquisition, the acquisition undervalued CPG and that the proxy statement was materially deficient. The new claim seeks rescissory damages in an amount to be proven at trial and disgorgement of profits from the sale. A hearing for CPG’s Motion to Dismiss is scheduled on February 28 ^th in the Court of Chancery of Delaware. At this early stage of the litigation, no outcome or possible loss or range of losses, if any, arising from the litigation is able to be estimated.

Appraisal Litigation

Following the consummation of the Merger, on September 9, 2016, multiple stakeholders, who, combined, allege ownership of approximately 7 million shares of CPG’s common stock, filed a petition for appraisal pursuant to 8 Del. C. § 262 in the Court of Chancery of the State of Delaware, captioned Dunham Monthly Distribution Fund et al v. Columbia Pipeline Group Inc . On September 15, 2016, another group of former CPG stockholders, who allege ownership of approximately 900,000 shares of CPG’s common stock, filed a second petition for appraisal, captioned Brookdale International Partners, L.P. et al . v. Columbia Pipeline Group Inc. Petitioners in the above-noted actions seek a judgment awarding them, among other things, the fair value of their CPG shares plus interest.  Collectively, these matters will be referred to as the “Appraisal Actions”.

On October 3, 2016, CPG filed its answer to the petition in the Dunham action and a verified list pursuant to 8 Del. C. § 262(f) naming, as of that filing, the persons that purported to demand appraisal of shares of CPG common stock. CPG filed its answer and verified lists in response to the Brookdale action on October 6, 2016. At this point, the total number of shares of CPG’s common stock for which appraisal has been demanded and not requested to be withdrawn is approximately 8.9 million, inclusive of the shares allegedly held by petitioners in the Appraisal Actions. The parties in the Appraisal Actions are in the early stages of discovery. The Court of Chancery has scheduled a 5 day trial commencing May 14, 2018 for the Appraisal Actions.

At this early stage of the litigation, no outcome or possible loss or range of losses, if any, arising from the litigation is able to be estimated.

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ITEM 3. LEGAL PROCEEDINGS

Environmental Litigation

On September 8, 2016, Keith Stutes, in his capacity as District Attorney for the 15 ^th Judicial District of the State of Louisiana, and the State of Louisiana (together, “Plaintiffs”) filed an action against certain oil and gas exploration and transportation companies, including Columbia Gulf Transmission, LLC (collectively, the “Defendants”),   associated with the development of the Tigre Lagoon Oil & Gas Field in Vermillion Parish in the 15 ^th Judicial District  Court for the Parish of Vermillion, captioned Keith Stutes, et al v. Gulfport Energy Corp, et al . The complaint alleges the Defendants’ operations were conducted in violation of the State and Local  Coastal Resources Management Act of 1978, as amended (the “CZM Act of 1978”) and that these activities caused substantial damage to the land and waterbodies located in the Coastal Zone, as defined in the CZM Act of 1978, within Vermillion Parish. It is possible that Columbia Gulf could incur substantial remediation and other costs and expenses in connection with this matter.  The amount of any potential judgment, assessments, penalties, fines, costs or expenses that may be incurred in connection with this litigation cannot be reasonably estimated at this time.

Please see Note 17 (“Other Commitments and Contingencies”) to Part II, Item 8 of this Form 10-K, which is incorporated by reference into this Part I, Item 3, for more information regarding legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

On July 2, 2015, our common stock began "regular way" trading on the NYSE under the symbol “CPGX.” Prior to that time, there was no public market for our common shares. On July 1, 2016, TransCanada closed the acquisition of CPG and each issued and outstanding share of our common stock was canceled. CPG’s sole stockholder is TransCanada PipeLine USA Ltd., a wholly owned subsidiary of TransCanada, and CPG’s equity is not publicly traded.

The following table sets forth the dividends declared on our common stock prior to the Merger for the periods indicated.

Declaration Date	Record Date	Payment Date	Dividend Per Common Share
July 2, 2015	July 31, 2015	August 20, 2015	$	0.12500
August 4, 2015	October 30, 2015	November 20, 2015	0.12500
January 29, 2016	February 8, 2016	February 19, 2016	0.12875
March 22, 2016	April 29, 2016	May 20, 2016	0.13375

Subsequent to the completion of the Merger, CPG distributed $110.5 million to TransCanada for the year ended December 31, 2016 .

Securities Authorized for Issuance under Equity Compensation Plans

None.

ITEM 6. SELECTED FINANCIAL DATA

The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(a) of Form 10-K.

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Columbia Pipeline Group, Inc.

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

Overview

We meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and have omitted specific information called for by this Item pursuant to General Instruction (I)(2)(a) of Form 10-K.

We are a growth-oriented Delaware corporation formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. On June 2, 2015, NiSource announced that its board of directors approved the separation of CPG from NiSource (the “Separation”) through the distribution of CPG common stock to holders of NiSource common stock as of June 19, 2015 (the “Record Date”). On July 1, 2015, NiSource distributed, pursuant to an effective registration statement on Form 10, 317.6 million shares, one share of CPG common stock for every one share of NiSource common stock held by NiSource stockholders on the Record Date. As of July 1, 2015, CPG was an independent, publicly traded company, and NiSource does not retain any ownership interest in CPG. CPG's common stock began trading "regular-way" under the ticker symbol "CPGX" on the NYSE on July 2, 2015.

On March 17, 2016, CPG entered into a Merger Agreement, among CPG, TCPL, US Parent, Merger Sub, and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016, Merger Sub was merged with and into CPG (the “Merger”) with CPG surviving the Merger as an indirect wholly owned subsidiary of TransCanada.

On July 1, 2016, TransCanada closed the acquisition of CPG valued at $13.0 billion, comprised of a purchase price of approximately $10.3 billion and CPG debt of approximately $2.7 billion. CPG became an indirect, wholly owned subsidiary of TransCanada as a result of the Merger. Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of CPG common stock, par value $0.01 per share, was canceled and converted into the right to receive $25.50 per share in cash, without interest. Upon completion of the transaction, TransCanada owns the general partner of CPPL, all of CPPL’s incentive distribution rights and all of CPPL’s subordinated units, which represent a 46.5% limited partnership interest in CPPL. As a result, CPPL is now effectively managed by TransCanada.

CPG has suspended its obligation to file periodic reports with the SEC based on its common stock as a result of the Merger. CPG has also suspended its obligations to file periodic reports with the SEC based on its senior notes and once it has filed its Form 10-K for the year ended December 31, 2016, it will no longer have reporting obligations with respect to its Notes. Refer to Note 6, "Long-Term Debt" for additional information.

CPPL Merger . On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.

The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the merger agreement and transactions contemplated by the merger agreement and determined that the merger agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the merger agreement and the merger transactions. The GP Board resolved that the merger agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the merger agreement and the merger transactions at the special meeting of the unitholders.

On February 16, 2017, the CPPL unaffiliated unitholders voted to approve the CPPL Merger. On February 17, 2017, CPG closed the transaction to acquire all outstanding publicly held common units valued at approximately $915.2 million. CPPL unaffiliated unitholders also received a regular quarterly distribution of $0.1975 per common unit and a pro-rated distribution for the period prior to the closing date. As a result of the CPPL Merger, CPPL became a wholly owned subsidiary of CPG.

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Columbia Pipeline Group, Inc.

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

Results of Operations

The following schedule presents our historical consolidated key operating and financial metrics.

Year Ended December 31, (in millions)	2016				2015				2014
Operating Revenues
Transportation revenues	$	1,155.1			$	1,054.4			$	990.8
Transportation revenues-affiliated	—				47.5				95.7
Storage revenues	196.5				171.4				144.0
Storage revenues-affiliated	—				26.2				53.2
Other revenues	30.4				35.4				64.3
Total Operating Revenues	1,382.0				1,334.9				1,348.0
Operating Expenses
Operation and maintenance	863.2				652.1				628.4
Operation and maintenance-affiliated	—				52.9				123.2
Depreciation and amortization	172.8				139.9				118.8
Gain on sale of assets	(16.6		)		(55.3		)		(34.5		)
Impairment of long-lived assets	26.1				2.4				—
Property and other taxes	83.2				75.3				67.1
Total Operating Expenses	1,128.7				867.3				903.0
Equity Earnings in Unconsolidated Affiliates	64.3				60.5				46.6
Operating Income	317.6				528.1				491.6
Other Income (Deductions)
Interest expense	(119.1		)		(67.6		)		—
Interest expense-affiliated	(2.1		)		(29.3		)		(62.0		)
Other, net	35.1				29.3				8.8
Total Other Deductions, net	(86.1		)		(67.6		)		(53.2		)
Income from Continuing Operations before Income Taxes	231.5				460.5				438.4
Income Taxes	77.8				153.0				169.7
Income from Continuing Operations	153.7				307.5				268.7
Income (Loss) from Discontinued Operations-net of taxes	0.2				(0.4		)		(0.6		)
Net Income	153.9				307.1				$	268.1
Less: Net income attributable to noncontrolling interest	37.1				39.9
Net income attributable to CPG	$	116.8			$	267.2
Throughput (MMDth)
Columbia Gas Transmission	1,759.5				1,460.1				1,379.4
Columbia Gulf	552.2				562.7				626.7
Crossroads	15.5				15.5				16.7
Total	2,327.2				2,038.3				2,022.8

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Operating Revenues . Operating revenues were $1,382.0 million for 2016 , an increase of $47.1 million from the same period in 2015 . The increase in operating revenues was primarily due to increased demand revenue of $108.3 million largely from the East Side Expansion, Broad Run Connector and Rayne XPress growth projects, and the CCRM. Additionally, there were increased shorter term transportation services of $5.0 million and higher commodity revenue of $3.7 million. These increases were partially offset by a decrease of $66.6 million attributable to the recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense, and lower mineral rights royalty revenue of $4.6 million.

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Columbia Pipeline Group, Inc.

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

Operating Expenses . Operating expenses were $1,128.7 million for 2016 , an increase of $261.4 million from the same period in 2015 . The increase in operating expenses was primarily due to higher costs related to the Merger of $174.8 million, increased costs related to the Separation of $56.0 million, decreased gains on the sale of assets of $38.7 million, primarily due to conveyances of mineral interests, higher depreciation and amortization of $32.9 million and increased property and other taxes of $6.3 million, both primarily due to higher levels of in-service assets. Additionally, there were higher impairment charges of $23.7 million due to the cancellation of IT system upgrades and increased maintenance expenses of $6.9 million. These variances were partially offset by $66.6 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and lower employee and administrative costs of $11.3 million.

Equity Earnings in Unconsolidated Affiliates . Equity Earnings in Unconsolidated Affiliates were $64.3 million in 2016 , an increase of $3.8 million compared to the same period in 2015 . Equity earnings increased primarily due to earnings generated by Millennium Pipeline and Pennant.

Other Income (Deductions) . Other income (deductions) in 2016 reduced income by $86.1 million compared to a reduction in income of $67.6 million in 2015 . The variance was primarily due to an increase in interest expense of $12.5 million and higher amortization of debt related costs of $1.2 million, both resulting from the issuance of long-term debt in May 2015, as well as $5.7 million of accelerated amortization of deferred costs associated with the CPG and CPPL revolving credit facilities that were terminated early. Additionally, there was higher expense of $4.1 million in the debt portion of AFUDC. These increased deductions were partially offset by an increase in other income of $6.6 million for the equity portion of AFUDC.

Income Taxes . The effective income tax rates were comparable at 33.6% and 33.2% in 2016 and 2015 , respectively.

Throughput . Throughput totaled 2,327.2 MMDth for 2016 , compared to 2,038.3 MMDth for the same period in 2015 . The increase of 288.9 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Operating Revenues . Operating revenues were $1,334.9 million for 2015 , a decrease of $13.1 million from the same period in 2014 . The decrease in operating revenues was primarily due 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 $2.3 million. These decreases were partially offset by increased demand revenue of $126.8 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 $867.3 million for 2015 , a decrease of $35.7 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 $24.4 million due to higher employee costs, increased depreciation of $21.1 million primarily due to increased capital expenditures related to projects placed in service, $18.8 million in Separation costs, higher outside service costs of $15.0 million and increased property and other taxes of $8.2 million.

Equity Earnings in Unconsolidated Affiliates . Equity Earnings in Unconsolidated Affiliates were $60.5 million in 2015 , an increase of $13.9 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 reduced income by $67.6 million compared to a reduction in income of $53.2 million in 2014 . The increased expense was primarily due to an increase of $36.1 million in interest expense. This was a result of increased interest of $67.5 million related to the May 2015 issuance of $2.75 billion of long-term debt at CPG, offset by lower affiliated interest of $30.6 million with NiSource Finance due to the repayment of long-term debt-affiliated. Additionally, this increase in interest expense was partially offset by an increase of $17.3 million in the equity portion of AFUDC and an increase in the debt portion of AFUDC of $6.7 million.

Income Taxes . The effective income tax rates were 33.2% and 38.7% in 2015 and 2014 , respectively. The change in the overall effective tax rates between 2015 and 2014 was primarily due to income before income tax attributable to noncontrolling interest

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Columbia Pipeline Group, Inc.

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

following CPPL’s IPO that is not subject to an income tax provision, as well as the effects of tax credits, state income taxes, utility rate-making and other permanent book-to-tax differences

Throughput . Throughput totaled 2,038.3 MMDth for 2015 , compared to 2,022.8 MMDth for the same period in 2014 . The increase of 15.5 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.

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 CPG’s results of operations and Consolidated 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 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 Balance Sheets were $176.9 million and $293.4 million at December 31, 2016 , and $182.7 million and $322.8 million at December 31, 2015 , respectively. For additional information, refer to Note 11, “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, 2016 . Regulatory assets of $58.9 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 6 years.

Pensions and Postretirement Benefits. CPG has defined benefit plans for both pensions and other postretirement benefits that cover its employees. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of CPG’s pensions and other postretirement benefits, please see Note 14, “Pension and Other Postretirement Benefits,” in the audited 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, 2016 and December 31, 2015 were $1,975.5 million pertaining to NiSource's acquisition of CEG on November 1, 2000.

The Predecessor 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 2015 and 2016, 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 these assessments indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value and no impairments is necessary.

Although there was no goodwill asset impairment as of May 1, 2016, 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

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Columbia Pipeline Group, Inc.

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

in the discount rate or changes in other key assumptions which require judgment and are forward looking in nature. In consideration of all relevant factors, there were no indicators that would require goodwill impairment testing subsequent to May 1, 2016.

Please see Notes 1-I and 9, “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 services 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.

CPG 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.

CPG includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $21.5 million , $26.5 million and $43.8 million for the years ended December 31, 2016 , 2015 and 2014 , 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 CPG 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 $16.9 million , $52.3 million and $34.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, and are included in “Gain on sale of assets” 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.

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Columbia Pipeline Group, Inc.

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: credit risk, interest rate risk and commodity market 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 have exposure to interest rate risk as a result of changes in interest rates that are indexed to short-term market interest rates on borrowings under our revolving credit facilities and former commercial paper program. 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 $2.2 million and $2.1 million for the years ended December 31, 2016 and 2015, respectively. 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 TransCanada’s policies relating to credit risk, which include guidelines for documenting management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by TransCanada’s corporate credit risk function which is independent of operations. Credit risk arises due to the possibility that a customer will not be able or willing to fulfill its obligations on a transaction on or before the settlement date.

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Columbia Pipeline Group, Inc.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index	Page
Report of Independent Registered Public Accounting Firm	38
Consolidated Balance Sheets	39
Statements of Consolidated and Combined Operations	41
Statements of Consolidated and Combined Comprehensive Income	42
Statements of Consolidated and Combined Cash Flows	43
Statements of Consolidated and Combined Equity	44
Notes to Consolidated and Combined Financial Statements	46

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Columbia Pipeline Group, Inc.

Houston, Texas

We have audited the accompanying financial statements of Columbia Pipeline Group, Inc. (the "Company") (a wholly owned subsidiary of TransCanada Corporation), which comprise the consolidated balance sheets as of December 31, 2016 and 2015, the related statements of consolidated and combined operations, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit 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 Columbia Pipeline Group, Inc. and subsidiaries at as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, on July 1, 2015 the Company completed its spin-off from NiSource Inc. and on July 1, 2016, TransCanada Corporation completed its acquisition of the Company. As discussed in Note 2 to the consolidated financial statements, on February 11, 2015, the Company completed the initial public offering of limited partner interests of Columbia Pipeline Partners LP for net proceeds of $1,168.4 million.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February 17, 2017

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

CONSOLIDATED BALANCE SHEETS

(in millions)	December 31, 2016				December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	79.9			$	930.9
Accounts receivable (less reserve of $0.3 and $0.6, respectively)	194.2				152.4
Accounts receivable-affiliated	55.8				—
Materials and supplies, at average cost	26.0				32.8
Exchange gas receivable	27.7				19.0
Deferred property taxes	61.2				52.0
Prepayments and other	28.9				48.5
Total Current Assets	473.7				1,235.6
Investments
Unconsolidated affiliates	446.7				438.1
Other investments	0.8				13.8
Total Investments	447.5				451.9
Property, Plant and Equipment
Property, plant and equipment	10,461.2				9,052.3
Accumulated depreciation and amortization	(3,126.2		)		(2,988.6		)
Net Property, Plant and Equipment	7,335.0				6,063.7
Other Noncurrent Assets
Regulatory assets	172.9				177.7
Goodwill	1,975.5				1,975.5
Postretirement and postemployment benefits assets	121.8				115.7
Deferred charges and other	11.3				15.5
Total Other Noncurrent Assets	2,281.5				2,284.4
Total Assets	$	10,537.7			$	10,035.6

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)	December 31, 2016				December 31, 2015
LIABILITIES, TEMPORARY EQUITY AND EQUITY
Current Liabilities
Short-term borrowings	$	—			$	15.0
Accounts payable	70.4				56.8
Accounts payable-affiliated	4.0				—
Customer deposits	17.3				17.9
Taxes accrued	116.9				106.0
Interest accrued	9.4				9.5
Exchange gas payable	27.2				18.6
Deferred revenue	3.9				15.0
Accrued capital expenditures	111.4				100.1
Accrued compensation and related costs	62.3				51.9
Other accruals	110.1				70.0
Total Current Liabilities	532.9				460.8
Noncurrent Liabilities
Long-term debt	2,728.6				2,725.6
Deferred income taxes	1,500.4				1,348.1
Accrued liability for postretirement and postemployment benefits	32.2				49.4
Regulatory liabilities	273.6				321.6
Asset retirement obligations	20.8				25.7
Other noncurrent liabilities	59.8				91.4
Total Noncurrent Liabilities	4,615.4				4,561.8
Total Liabilities	5,148.3				5,022.6
Commitments and Contingencies (Refer to Note 17)
Temporary Equity
Redeemable noncontrolling interest	952.9				—
Equity
Common stock, $0.01 par value, 10,001,000 and 2,000,000,000 shares authorized, respectively; 10,000,150 and 399,841,350 shares outstanding, respectively	0.1				4.0
Additional paid-in capital	4,513.8				4,032.7
(Accumulated deficit) Retained earnings	(53.5		)		46.9
Accumulated other comprehensive loss	(23.9		)		(27.0		)
Total CPG Equity	4,436.5				4,056.6
Noncontrolling Interest	—				956.4
Total Equity	4,436.5				5,013.0
Total Liabilities, Temporary Equity and Equity	$	10,537.7			$	10,035.6

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

Year Ended December 31 , (in millions)	2016				2015				2014
Operating Revenues
Transportation revenues	$	1,155.1			$	1,054.4			$	990.8
Transportation revenues-affiliated	—				47.5				95.7
Storage revenues	196.5				171.4				144.0
Storage revenues-affiliated	—				26.2				53.2
Other revenues	30.4				35.4				64.3
Total Operating Revenues	1,382.0				1,334.9				1,348.0
Operating Expenses
Operation and maintenance	863.2				652.1				628.4
Operation and maintenance-affiliated	—				52.9				123.2
Depreciation and amortization	172.8				139.9				118.8
Gain on sale of assets	(16.6		)		(55.3		)		(34.5		)
Impairment of long-lived assets	26.1				2.4				—
Property and other taxes	83.2				75.3				67.1
Total Operating Expenses	1,128.7				867.3				903.0
Equity Earnings in Unconsolidated Affiliates	64.3				60.5				46.6
Operating Income	317.6				528.1				491.6
Other Income (Deductions)
Interest expense	(119.1		)		(67.6		)		—
Interest expense-affiliated	(2.1		)		(29.3		)		(62.0		)
Other, net	35.1				29.3				8.8
Total Other Deductions, net	(86.1		)		(67.6		)		(53.2		)
Income from Continuing Operations before Income Taxes	231.5				460.5				438.4
Income Taxes	77.8				153.0				169.7
Income from Continuing Operations	153.7				307.5				268.7
Income (Loss) from Discontinued Operations-net of taxes	0.2				(0.4		)		(0.6		)
Net Income	153.9				307.1				$	268.1
Less: Net income attributable to noncontrolling interest	37.1				39.9
Net Income Attributable to CPG	$	116.8			$	267.2
Amounts Attributable to CPG:
Net income from continuing operations	$	116.6			$	267.6			$	268.7
Net income (loss) from discontinued operations-net of taxes	0.2				(0.4		)		(0.6		)
Net Income Attributable to CPG	$	116.8			$	267.2			$	268.1

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

STATEMENTS OF CONSOLIDATED AND COMBINED COMPREHENSIVE INCOME

Year Ended December 31, (in millions, net of taxes)	2016				2015				2014
Net Income	$	153.9			$	307.1			$	268.1
Other comprehensive income
Net unrealized gain on cash flow hedges (1)	1.3				0.2				1.0
Unrecognized pension and OPEB benefit (cost) (2)(3)	2.0				5.2				(9.7		)
Total other comprehensive income (loss)	3.3				5.4				(8.7		)
Total Comprehensive Income	157.2				312.5				259.4
Less: Comprehensive Income-noncontrolling interest	37.3				40.0				—
Comprehensive Income-controlling interests	$	119.9			$	272.5			$	259.4

⁽¹⁾ Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.7 million , $0.2 million and $0.7 million tax expense in 2016 , 2015 and 2014 , respectively.

⁽²⁾ Unrecognized pension and OPEB benefit (cost), net of $1.3 million tax expense, $1.2 million tax benefit, and $6.1 million tax benefit in 2016 , 2015 and 2014 , respectively.

⁽³⁾ Unrecognized pension and OPEB benefits are primarily related to pension and OPEB remeasurements recorded during 2016 and 2015.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Columbia Pipeline Group, Inc.

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

Year Ended December 31, (in millions)	2016				2015				2014
Operating Activities
Net Income	$	153.9			$	307.1			$	268.1
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization	172.8				139.9				118.8
Deferred income taxes and investment tax credits	129.4				131.9				142.6
Deferred revenue	(3.2		)		4.2				1.6
Equity-based compensation expense and profit sharing contribution	1.7				9.4				6.3
Gain on sale of assets	(16.6		)		(55.3		)		(34.5		)
Impairment of long-lived assets	26.1				2.4				—
Equity earnings in unconsolidated affiliates	(64.3		)		(60.5		)		(46.6		)
(Income) loss from discontinued operations-net of taxes	(0.2		)		0.4				0.6
Amortization of debt related costs	10.2				3.1				—
AFUDC equity	(34.9		)		(28.3		)		(11.0		)
Distributions of earnings received from equity investees	61.5				57.2				37.8
Changes in Assets and Liabilities:
Accounts receivable	(39.2		)		(17.4		)		(20.3		)
Accounts receivable-affiliated	(55.8		)		34.7				(3.6		)
Accounts payable	16.0				(5.0		)		2.8
Accounts payable-affiliated	3.4				(53.6		)		12.4
Customer deposits	(0.6		)		(22.9		)		77.5
Taxes accrued	8.8				8.2				12.0
Interest accrued	0.1				9.4				—
Exchange gas receivable/payable	(0.2		)		(0.3		)		1.1
Other accruals	1.7				50.2				0.9
Prepayments and other current assets	16.2				(27.1		)		(4.4		)
Regulatory assets/liabilities	11.2				20.2				9.0
Postretirement and postemployment benefits	(14.5		)		(4.4		)		(1.3		)
Deferred charges and other noncurrent assets	(8.0		)		(16.3		)		(4.3		)
Other noncurrent liabilities	(15.6		)		6.5				0.7
Net Operating Activities from Continuing Operations	359.9				493.7				566.2
Net Operating Activities from (used for) Discontinued Operations	0.3				(0.2		)		(1.4		)
Net Cash Flows from Operating Activities	360.2				493.5				564.8
Investing Activities
Capital expenditures	(1,438.1		)		(1,181.0		)		(747.2		)
Insurance recoveries	3.0				2.1				11.3
Changes in short-term lendings-affiliated	—				145.5				(57.2		)
Proceeds from disposition of assets	10.4				77.6				9.3
Contributions to equity investees	(6.2		)		(1.4		)		(69.2		)
Distributions from equity investees	2.2				16.0				—
Other investing activities	0.6				(27.4		)		(7.1		)
Net Cash Flows used for Investing Activities	(1,428.1		)		(968.6		)		(860.1		)
Financing Activities
Change in short-term borrowings	(15.0		)		15.0				—
Change in short-term borrowings-affiliated	500.0				(252.5		)		(467.1		)
Payment of short-term borrowings-affiliated	(500.0		)		—				—
Issuance of long-term debt	—				2,745.9				—
Payment of capital lease obligations and other debt related costs	(5.4		)		(23.6		)		(6.4		)
Issuance of long-term debt-affiliated	—				1,217.3				768.9
Payments of long-term debt-affiliated, including current portion	—				(2,807.8		)		—
Proceeds from issuance of common units, net of offering costs	—				1,168.4				—
Issuance of common stock, net of offering costs	—				1,394.7				—
Issuance of common stock to TransCanada	500.1				—				—
Distribution of IPO proceeds to NiSource	—				(500.0		)		—
Distribution to NiSource	—				(1,450.0		)		—
Distribution to noncontrolling interest	(41.0		)		(23.2		)		—
Acquisition of treasury stock	(6.2		)		—				—
Dividends paid - common stock	(105.1		)		(79.5		)		—
Dividends paid - TransCanada	(110.5		)		—				—
Transfer from NiSource	—				0.8				—
Net Cash Flows from Financing Activities	216.9				1,405.5				295.4
Change in cash and cash equivalents	(851.0		)		930.4				0.1
Cash and cash equivalents at beginning of period	930.9				0.5				0.4
Cash and Cash Equivalents at End of Period	$	79.9			$	930.9			$	0.5

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

C olumbia Pipeline Group, Inc.

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(in millions)	Common Stock				Treasury Stock				Additional Paid-in Capital				(Accumulated Deficit) Retained Earnings				Net Parent Investment				Accumulated Other Comprehensive Loss				Total Equity				Noncontrolling Interest (4)
Balance as of January 1, 2014 - Predecessor	$	—			$	—			$	—			$	—			$	3,941.4			$	(25.8	)		$	3,915.6			$	—
Net Income	—				—				—				—				268.1				—				268.1				—
Other comprehensive loss, net of tax	—				—				—				—				—				(8.7		)		(8.7		)		—
Net transfers from parent	—				—				—				—				1.3				—				1.3				—
Balance as of December 31, 2014	$	—			$	—			$	—			$	—			$	4,210.8			$	(34.5	)		$	4,176.3			$	—
Net Income	—				—				—				126.4				140.8				—				267.2				39.9
Other comprehensive income, net of tax	—				—				—				—				—				5.3				5.3				0.1
Allocation of AOCI to noncontrolling interest	—				—				—				—				—				2.2				2.2				(2.2		)
Issuance of common units of CPPL	—				—				—				—				—				—				—				1,168.4
Distribution of IPO proceeds to NiSource	—				—				—				—				(500.0		)		—				(500.0		)		—
Distribution to NiSource	—				—				—				—				(1,450.0		)		—				(1,450.0		)		—
Sale of interest in Columbia OpCo to CPPL (1)	—				—				—				—				227.1				—				227.1				(227.1		)
Distributions to noncontrolling interest	—				—				—				—				—				—				—				(23.2		)
Net transfers from NiSource prior to Separation	—				—				—				—				6.3				—				6.3				—
Reclassification of net parent investment to additional paid-in capital	—				—				2,635.0				—				(2,635.0		)		—				—				—
Issuance of common stock at Separation	3.2				—				(3.2		)		—				—				—				—				—
Net transfers from NiSource subsequent to Separation	—				—				1.0				—				—				—				1.0				0.5
Issuance of common stock, net of offering costs	0.8				—				1,393.9				—				—				—				1,394.7				—
Long-term incentive plan	—				—				6.0				—				—				—				6.0				—
Common stock dividends (2)	—				—				—				(79.5		)		—				—				(79.5		)		—
Balance as of December 31, 2015	$	4.0			$	—			$	4,032.7			$	46.9			$	—			$	(27.0	)		$	4,056.6			$	956.4
Net Income	—				—				—				116.8				—				—				116.8				37.1
Other comprehensive income, net of tax	—				—				—				—				—				3.1				3.1				0.2
Common stock dividends (2)	—				—				—				(105.1		)		—				—				(105.1		)		—
Dividends to TransCanada	—				—				—				(110.5		)		—				—				(110.5		)		—
Common stock purchased by TransCanada and retired	(4.0		)		—				(10,212.7		)		—				—				—				(10,216.7		)		—
Issuance of common stock associated with Merger	0.1				—				10,216.7				—				—				—				10,216.8				—
Treasury stock acquired	—				(6.2		)		—				—				—				—				(6.2		)		—
Treasury stock retirement	—				6.2				(4.6		)		(1.6		)		—				—				—				—
Distributions to noncontrolling interest	—				—				—				—				—				—				—				(41.0		)
Issuance of stock to TransCanada (3)	—				—				500.0				—				—				—				500.0				—
Long-term incentive plan	—				—				(18.3		)		—				—				—				(18.3		)		0.2
Balance as of December 31, 2016	$	0.1			$	—			$	4,513.8			$	(53.5	)		$	—			$	(23.9	)		$	4,436.5			$	952.9

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

C olumbia Pipeline Group, Inc.

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

⁽¹⁾ Represents the sale 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 the noncontrolling interest by the same amount it increases the net parent investment because CPPL's purchase price for its additional 8.4% interest in Columbia OpCo exceeded book value.

⁽²⁾ CPG declared and paid common dividends totaling $0.2625 per share and $0.25 per share for the years ended December 31, 2016 and 2015 , respectively.

⁽³⁾ In December 2016, CPG issued 50 shares of common stock, $0.01 par value at a purchase price of $10.0 million per share, for a total of $500.0 million to US Parent.

⁽⁴⁾ As of December 31, 2016 and as a result of the CPPL Merger Agreement, CPPL's common units now contain a redemption feature within the control of CPPL's unaffiliated unitholders. The existence of the redemption feature causes CPG's noncontrolling interest to be redeemable at an amount other than fair value, thus requiring CPG to present noncontrolling interest as temporary equity on the Consolidated Balance Sheets. Please see Note 1, "Nature of Operations and Summary of Significant Accounting Policies" in the Notes to Consolidated and Combined Financial Statements for further discussion.

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

 

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C olumbia Pipeline Group, Inc.

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 Group, Inc. ("CPG") is a growth-oriented Delaware corporation formed on September 26, 2014 to own, operate and develop a portfolio of pipelines, storage and related midstream assets. 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. CPG indirectly owns the general partner of CPPL and all of CPPL’s subordinated units and incentive distribution rights. CPG did not have any material assets or liabilities as a separate corporate entity until the contribution of CEG from NiSource on February 11, 2015. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows for CPG's Predecessor (the "Predecessor").

CPG is engaged in regulated 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 such as midstream services, including gathering, treating, conditioning, processing, compression and liquids handling and development of mineral rights positions. The regulated services are performed under a tariff at rates subject to FERC approval.

Separation. On June 2, 2015, NiSource announced that its board of directors approved the separation of CPG from NiSource (the “Separation”) through the distribution of CPG common stock to holders of NiSource common stock as of June 19, 2015 (the “Record Date”). On July 1, 2015, NiSource distributed, pursuant to an effective registration statement on Form 10, 317.6 million shares, one share of CPG common stock for every one share of NiSource common stock held by NiSource stockholders on the Record Date. As of July 1, 2015, CPG was an independent, publicly traded company, and NiSource did not retain any ownership interest in CPG. CPG's common stock began trading "regular-way" under the ticker symbol "CPGX" on the NYSE on July 2, 2015. In connection with the Separation, CPG completed the following transactions:

•	In May 2015, CPG completed its private placement of senior notes and received proceeds of approximately $2,722.3 million . CPG utilized a portion of the proceeds to repay approximately $1,087.3 million of intercompany debt and short-term borrowings, including, net amounts due from the money pool between CPG and NiSource Finance;

•	CPG further utilized the proceeds from the senior notes to make a cash distribution of approximately $1,450.0 million to NiSource; and

•	Accounts related to NiSource and its subsidiaries, including accounts receivable and accounts payable, were reclassified from affiliated to non-affiliated.

Agreements with NiSource following the Separation . CPG entered into the Separation and Distribution Agreement and several other agreements with NiSource to effect the Separation and provide a framework for CPG’s relationship with NiSource, and its subsidiaries, after the Separation. The Separation and Distribution Agreement contains many of the key provisions related to CPG’s separation from NiSource and the distribution of CPG’s shares of common stock to NiSource’s stockholders, including cross-indemnities between CPG and NiSource. In general, NiSource has agreed to indemnify CPG for any liabilities relating to NiSource's business and CPG has agreed to indemnify NiSource for any liabilities relating to CPG's business. In addition to the Separation and Distribution Agreement, CPG entered into the following agreements with NiSource related to the Separation:

•	Tax Allocation Agreement - Provides for the respective rights, responsibilities, and obligations of NiSource and CPG with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, tax contests, and certain other matters regarding taxes.

•	Employee Matters Agreement - Provides for the respective obligations to employees and former employees who are or were associated with CPG (including those employees who transferred employment from NiSource to CPG prior to the Separation) and for other employment and employee benefits matters.

•	Transition Services Agreement - Provides for the provision of certain transitional services by NiSource to CPG, and vice versa. The services may include the provision of administrative and other services identified by the parties. The charge for these services is expected to be based on actual costs incurred by the party rendering the services without profit.

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C olumbia Pipeline Group, Inc.

Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Merger. On March 17, 2016 , CPG entered into an Agreement and Plan of Merger (the "Merger Agreement"), among CPG, TCPL, US Parent, Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent ("Merger Sub"), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016 , Merger Sub was merged with and into CPG (the "Merger") with CPG surviving the Merger as an indirect wholly owned subsidiary of TransCanada.

On July 1, 2016 , TransCanada closed the acquisition of CPG valued at $13.0 billion , comprised of a purchase price of approximately $10.3 billion and CPG debt of approximately $2.7 billion . CPG became an indirect, wholly owned subsidiary of TransCanada as a result of the Merger. Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of CPG common stock, par value $0.01 per share, was canceled and converted into the right to receive $25.50 per share in cash, without interest. Upon completion of the transaction, TransCanada owns the general partner of CPPL, all of CPPL’s incentive distribution rights and all of CPPL's subordinated units, which represent a 46.5% limited partnership interest in CPPL. As a result, CPPL is now effectively managed by TransCanada.

For the year ended December 31, 2016 , CPG incurred Merger transaction costs of $66.6 million , including legal, advisory and other related fees. These costs are included in "Operation and maintenance" on the Statements of Consolidated and Combined Operations. Approximately $104.9 million of employee related costs were incurred subsequent to the Merger. Additionally as a result of the Merger, CPG recognized an impairment charge of $26.1 million related to the cancellation of IT system upgrades that were in process prior to the Merger.

CPG has suspended its obligation to file periodic reports with the SEC based on its common stock as a result of the Merger. CPG has also suspended its obligations to file periodic reports with the SEC based on its senior notes and once it has filed its Form 10-K for the year ended December 31, 2016, it will no longer have reporting obligations with respect to its senior notes. Refer to Note 6, "Long-Term Debt" for additional information on CPG's senior notes.

CPPL Merger. On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger ("CPPL Merger Agreement") with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.

The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the CPPL Merger Agreement and transactions contemplated by the CPPL Merger Agreement and determined that the CPPL Merger Agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the CPPL Merger Agreement and the merger transactions. The GP Board resolved that the CPPL Merger Agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the CPPL Merger Agreement and the merger transactions at the special meeting of the unitholders.

On February 16, 2017, the CPPL unaffiliated unitholders voted to approve the CPPL Merger. On February 17, 2017, CPG closed the transaction to acquire all outstanding publicly held common units valued at approximately $915 million . CPPL unaffiliated unitholders also received a regular quarterly distribution of $0.1975 per common unit and a pro-rated distribution for the period prior to the closing date. As a result of the CPPL Merger, CPPL became a wholly owned subsidiary of CPG.

As of December 31, 2016 and as a result of the CPPL Merger Agreement, CPPL's common units now contain a redemption feature within the control of CPPL's unaffiliated unitholders. The existence of the redemption feature causes CPG's noncontrolling interest to be redeemable at an amount other than fair value, thus requiring CPG to present noncontrolling interest as temporary equity on the Consolidated Balance Sheets. The redeemable noncontrolling interest is recorded at its current book value and will be adjusted each period for net earnings and other comprehensive income attributable to the noncontrolling interest. As of December 31, 2016, CPG did not consider noncontrolling interest to be probable of becoming redeemable given the special meeting of CPPL's unitholders had not yet occurred and there could be no certainty the unaffiliated unitholders will vote to approve the merger.

CPG’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, Crossroads, CPGSC, CEG, Columbia Remainder Corporation, CPP GP LLC, CPPL, OpCo GP and Columbia OpCo. All intercompany transactions and balances have been eliminated. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline and Pennant.

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C olumbia Pipeline Group, Inc.

Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 CPG'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 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 CPG to recover its costs in the future, all or a portion of CPG’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 CPG’s existing regulatory assets and liabilities could result. If CPG is unable to continue to apply the provisions of regulatory accounting, CPG would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, CPG’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 11, "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. CPG'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. CPG's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties.

 

CPG 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:

	2016						2015						2014
	Debt			Equity			Debt			Equity			Debt			Equity
Columbia Gas Transmission	0.6	%		4.8	%		1.8	%		6.3	%		0.9	%		3.0	%
Columbia Gulf	0.6	%		3.7	%		2.9	%		6.3	%		2.1	%		9.4	%

CPG 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.

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, 2016 , 2015 and 2014 . Gas stored-base gas is included in Property, plant and equipment on the Consolidated 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

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

period of five years. CPG amortized $20.4 million in 2016 , $8.7 million in 2015 and $4.3 million in 2014 related to software costs. CPG’s unamortized software balance was $72.1 million and $59.8 million at December 31, 2016 and 2015 , respectively. The increase in software amortization and unamortized software balance is primarily due to software placed in service subsequent to the Separation. The additional software was necessary for CPG to operate as an independent company.

I.        Goodwill.     CPG 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 9, "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. CPG recognized an impairment loss of $26.1 million , $2.4 million and zero for the years ended December 31, 2016 , 2015 and 2014 , respectively. As a result of the Merger, CPG recognized an impairment loss for the year ended December 31, 2016 related to the cancellation of IT system upgrades that were in process prior to the Merger.

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.

CPG 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.

CPG 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 $21.5 million , $26.5 million and $43.8 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations.

CPG 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 CPG 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 $16.9 million , $52.3 million and $34.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations.

L.        Estimated Rate Refunds .    CPG 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.

M.        Accounting for Exchange and Balancing Arrangements of Natural Gas.     CPG enters into balancing and exchange arrangements of natural gas as part of its operations. CPG 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 CPG’s Consolidated Balance Sheets, as appropriate.

N.        Income Taxes and Investment Tax Credits.     CPG records income taxes to recognize full inter period tax allocations. Under the liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. To the extent certain deferred income taxes of CPG are recoverable or payable through future rates, regulatory assets and liabilities have been established.

Subsequent to the Merger, CPG is included in the consolidated Federal income tax return filed by US Parent and is a party to a Federal Tax Allocation Agreement with US Parent. The tax allocation agreement allocates to CPG an amount of Federal income tax liabilities and benefits similar to that which would be if CPG had filed a separate return. For states that require consolidated or combined returns, CPG will be included with certain TransCanada affiliates and will settle its state income tax liabilities and benefits with US Parent.

In prior years, and for the period ending July 1, 2015, CPG joined in the filing of consolidated federal and state income tax returns with NiSource. CPG was a party to an agreement (“Tax Allocation Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Allocation Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, the Tax Allocation Agreement provides that tax benefits associated with NiSource parent’s tax losses, excluding tax benefits from interest expense on acquisition debt, are allocated to and reduce the income tax liability of all NiSource subsidiaries having a positive separate company tax liability in a particular tax year.

The amounts of such tax benefits allocated to CPG that were recorded in equity in 2016 , 2015 and 2014 were zero , $5.8 million and $1.3 million , respectively.

O.       Environmental Expenditures.     CPG 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 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. CPG establishes regulatory assets on the Consolidated 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.     CPG 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 CPG (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.

CPG owns a 50.0% interest in Hardy Storage for the periods presented. CPG reflects 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% . During 2016, Williams Partners funded additional specified growth projects. As a result Columbia Midstream's ownership interest decreased to 47.0% . CPG 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.

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors.

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2016 and 2015 :

(in millions)	2016				2015
Beginning Balance	$	1.7			$	14.9
Additions pending the determination of proved reserves	—				1.3
Reclassifications of proved properties	(1.3		)		(14.5		)
Ending Balance	$	0.4			$	1.7

As of December 31, 2016 , 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.    CPPL Initial Public Offering

On December 5, 2007, NiSource formed CPPL (NYSE: CPPL) to own, operate and develop a portfolio of pipelines, storage and related assets.

On February 11, 2015 , CPPL completed its offering of 53.8 million common units representing limited partner interests, constituting 53.5% of CPPL's outstanding limited partner interests. CPPL received $1,168.4 million of net proceeds from the IPO. CPG owns the general partner of CPPL and all of CPPL's subordinated units and incentive distribution rights. The assets of CPPL consist of a 15.7% limited partner interest in Columbia OpCo, which prior to the Separation, consisted of substantially all of NiSource's Columbia Pipeline Group Operations segment. The operations of CPPL are consolidated into CPG's results. As of December 31, 2016 , the portion of CPPL owned by the public is reflected as a noncontrolling interest in the Consolidated and Combined Financial Statements.

The table below summarizes the effects of the changes in CPG's ownership interest in Columbia OpCo on equity:

Year Ended December 31, (in millions)	2016				2015
Net income attributable to CPG	$	116.8			$	267.2
Increase in CPG's net parent investment for the sale of 8.4% of Columbia OpCo	—				227.1
Change from net income attributable to CPG and transfers to noncontrolling interest	$	116.8			$	494.3

3.	Recent Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . ASU 2017-04 simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. CPG is required to adopt ASU 2017-04 for its annual or any interim goodwill impairment tests for annual periods beginning after December 15, 2019, and the guidance is to be applied on a prospective basis. CPG is currently evaluating the impact the adoption of ASU 2017-04 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. ASU 2017-01 provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. CPG is required to adopt ASU 2017-01 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied on a

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

prospective basis. CPG is currently evaluating the impact the adoption of ASU 2017-01 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.

In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control , which amends the guidance on related parties that are under common control. Specifically, ASU 2016-17 requires that a single decision maker consider indirect interest held by related parties under common control on a proportionate basis in a manner consistent with its evaluation of indirect interests held through other related parties. CPG is required to adopt ASU 2016-17 for periods beginning after December 15, 2016, including interim periods, and the guidance is to be applied on a retrospective basis. CPG is currently evaluating the impact the adoption of ASU 2016-17 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate the impact will be material.

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Asset Transfers of Assets Other Than Inventory , which removes the prohibition in ASC 740 against the immediate recognition of the current and deferred income tax effects of intra-entity transfers of assets other than inventory. CPG is required to adopt ASU 2016-16 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied on a modified retrospective basis, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2016-16 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments . ASU 2016-15 amends the guidance in ASC 230 on the classification of certain cash receipts and payments in the statement of cash flows. CPG is required to adopt ASU 2016-15 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied retrospectively, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2016-15 will have 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. In March 2016, the FASB issued ASU 2016-08, which amends the principal-versus-agent implementation guidance and illustrations in ASU 2014-09. Among other things, ASU 2016-08 clarifies that an entity should evaluate whether it is the principal or the agent for each specified good or service promised in a contract with a customer. In April 2016, the FASB issued ASU 2016-10, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, which contains narrow scope improvements for certain aspects of ASU 2014-09 including collectability, presentation of sales tax and other similar taxes collected from customers, noncash consideration, contract modifications and completed contracts at transition and transition technical correction. CPG is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine the impact the adoption of ASU 2014-09, and the related ASUs, will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

In March 2016, the FASB issued ASU 2016-09,  Improvements to Employee Share-Based Payment Accounting (Topic 718) . ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other provisions, ASU 2016-09 requires that all income tax effects of awards are recognized in the income statement when the awards vest or are settled and also allows an employer to make a policy election to account for forfeitures as they occur. CPG is required to adopt ASU 2016-09 for periods beginning after December 15, 2016, including interim periods, with early adoption permitted if all of the amendments are adopted in the same period. Each amendment has varying transition requirements. CPG expects to adopt ASU 2016-09 in the first quarter of 2017. Upon adoption, CPG will record a $9.9 million increase to beginning retained earnings with a corresponding increase in deferred tax assets representing the excess tax benefits generated in years prior to adoption of ASU 2016-09.  Prior to the adoption of ASU 2016-09, CPG was precluded from recording this increase in deferred tax assets due to having a cumulative net operating loss carryforward for Federal income taxes.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . ASU 2016-02 introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in ASC 606, the FASB's new revenue recognition standard (e.g., those related to evaluating when profit can be recognized). Furthermore, ASU 2016-02 addresses other concerns related to the current leases model. For example, ASU 2016-02 eliminates the requirement in current U.S. GAAP for an entity to use bright-line tests in determining lease classification. The standard also requires lessors to increase the transparency of their exposure to changes in value of their residual assets and how they manage that exposure. CPG is required to adopt ASU 2016-02 for periods beginning after December 15, 2018, including interim periods, with early adoption permitted. CPG is currently identifying existing lease agreements that may have an impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

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. CPG adopted ASU 2015-03 and ASU 2015-15 as of January 1, 2016, resulting in the reclassification of unamortized balance of debt issuance costs from "Deferred charges and other" to "Long-term debt." This change in accounting principle was applied retrospectively. As of December 31, 2015, the balance of unamortized debt issuance costs recorded in "Deferred charges and other" was $20.6 million . As a result of the retrospective adjustment, the December 31, 2015 balances of "Deferred charges and other" and "Long-term debt" were reduced by $20.6 million on the Consolidated Balance Sheets and 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. CPG retrospectively adopted ASU 2015-02 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

4.    Transactions with Affiliates

Transactions with TransCanada

Subsequent to the completion of the Merger, CPG engaged in transactions with subsidiaries of TransCanada, which are deemed to be affiliates of CPG. Transactions with affiliates subsequent to the Merger are summarized below:

Interest Expense. CPG was charged interest for short-term borrowings of $2.1 million for the year ended December 31, 2016.

Accounts Receivable . The affiliated accounts receivable balance of $55.8 million due from TransCanada primarily represents amounts allocated to CPG pursuant to TransCanada's tax allocation agreement.

Accounts Payable . The affiliated accounts payable balance of $4.0 million primarily includes amounts due for insurance coverage and interest payable to TransCanada.

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG-TransCanada PipeLine USA Ltd. Revolving Credit Facility. Subsequent to the completion of the Merger, CPG entered into a $2,000.0 million revolving credit facility with US Parent. The revolving credit facility became effective as of July 1, 2016, with no termination date. The revolving credit facility is available for general corporate purposes, including capital expenditures.

Loans under the revolving credit facility bear interest at CPG's option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent per annum, (b) the reference prime rate per annum as defined by Bloomberg Professional Service or (c) the rate equal to LIBOR for a one month LIBOR period for each day the loan is outstanding, plus 1.000 percent per annum, each of which is subject to a margin of 0.250 percent per annum, or (ii) the LIBOR rate plus a margin of 1.250 percent per annum.

As of December 31, 2016 , CPG had no outstanding borrowings under the revolving credit facility, with a weighted average interest rate of 1.98% .

Dividends to TransCanada . Subsequent to the completion of the Merger, CPG distributed $110.5 million to TransCanada for the year ended December 31, 2016 .

Transactions with NiSource

Prior to the Separation, CPG engaged in transactions with subsidiaries of NiSource, which at that time were deemed to be affiliates of CPG. The Separation occurred on July 1, 2015 and for periods after this date CPG and subsidiaries of NiSource are no longer affiliates. Transactions with affiliates prior to the Separation are summarized below:

Transportation, Storage and Other Revenues . CPG provided natural gas transportation, storage and other services to subsidiaries of NiSource, former affiliates. For the year ended December 31, 2015 , CPG recognized transportation revenues of $47.5 million , storage revenues of $26.2 million and other revenues of $0.2 million . For the year ended December 31, 2014 , CPG recognized transportation revenues of $95.7 million , storage revenues of $53.2 million and other revenues of $0.3 million .

Operation and Maintenance Expense . CPG received executive, financial, legal, information technology and other administrative and general services from a former affiliate, NiSource Corporate Services. Expenses incurred as a result of these services consisted of employee compensation and benefits, outside services and other expenses. CPG was 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. For the years ended December 31, 2015 and 2014 , operation and maintenance expense was $52.9 million and $123.2 million , respectively.

Interest Expense and Income . Prior to the private placement of senior notes on May 22, 2015, CPG paid NiSource interest for intercompany long-term debt outstanding. CPG was charged interest for long-term debt of $31.0 million and $61.6 million for the years ended December 31, 2015 and 2014 , respectively, offset by associated AFUDC of $2.4 million and $2.7 million for the years ended December 31, 2015 and 2014 , respectively.

Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the closing date of CPPL's IPO. Following the Separation, the agreement is 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 CPPL's IPO, the subsidiaries of CPG participated in a similar money pool agreement with NiSource Finance. Prior to the Separation, NiSource Corporate Services administered the money pools. Prior to the Separation, the cash accounts maintained by the subsidiaries of Columbia OpCo and CPG were 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. The amount of interest expense and income for short-term borrowings was determined by the net position of each subsidiary in the money pool. Subsequent to the Separation, the intercompany money pool balances and related interest expense and income are eliminated as intercompany activity. The money pool weighted-average interest rate at June 30, 2015 was 1.21% . The interest expense for short-term borrowings charged for the years ended December 31, 2015 and 2014 was $0.7 million and $3.1 million , respectively.

Dividends to NiSource . During the year ended December 31, 2015 , CPG distributed $500.0 million of the proceeds from CPPL's IPO to NiSource as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and $1,450.0 million of proceeds related to the issuance of senior notes in May 2015. CPG paid no dividends to NiSource in the year ended December 31, 2014 . There were no restrictions on the payment by CPG of dividends to NiSource.

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

5.    Short-Term Borrowings

New CPG Revolving Credit Facility. On December 16, 2016, CPG entered into a $1,000.0 million senior revolving credit facility. The revolving credit facility is guaranteed by TCPL. The initial maturity date is December 15, 2017, subject to an extension permitted under the revolving credit facility. CPG expects that the revolving credit facility will be utilized for the financing of capital expenditures and for CPG’s general corporate purposes, including working capital. Obligations under the revolving credit facility are unsecured.

Loans under the revolving credit facility will bear interest at CPG's option at either (i) LIBOR plus a margin ranging from 0.75% to 1.25% or (ii) a base rate plus a margin ranging from 0.00% to 0.25% , in each case, depending upon the credit rating of the TCPL’s senior, unsecured, long-term debt (the "Index Debt Rating"). In addition, CPG is obligated to pay a quarterly commitment fee equal to a rate per annum ranging from 0.04% to 0.15% , depending upon the Index Debt Rating, and calculated daily based on the unused commitments during such previous quarter.

TCPL shall comply, and shall cause CPG and each of TCPL’s subsidiaries to comply, with a number of customary affirmative and negative covenants, including limitations with respect to liens, indebtedness, distributions, mergers, consolidations, and asset sales, among others. TCPL shall not, and shall not permit any of its subsidiaries to, incur additional indebtedness (other than indebtedness maturing 24 months or less after such indebtedness is incurred) if immediately after incurring such indebtedness, the ratio of indebtedness of TCPL and its subsidiaries (on a consolidated basis) to the total capitalization of TCPL and its subsidiaries (on a consolidated basis) would be in excess of 0.75 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 (subject to applicable grace periods).

As of December 31, 2016 , CPG had no outstanding borrowings under the revolving credit facility.

As of December 31, 2015 , CPG had no outstanding borrowings and had $18.1 million in letters of credit under the previous revolving credit facility. On July 1, 2016, in connection with the Merger, all existing letters of credit were migrated to a TransCanada credit facility and the CPG revolving credit facility was terminated. As a result, CPG accelerated the amortization of $4.3 million of deferred costs associated with the revolving credit facility, which is included in interest expense for the year ended December 31, 2016 .

CPPL Revolving Credit Facility. As of December 31, 2015 , CPPL had $15.0 million in outstanding borrowings, with a weighted average interest rate of 1.28% , and issued no letters of credit under the revolving credit facility. On June 29, 2016, in anticipation of the Merger, all outstanding borrowings, facility fees and interest were paid in full and the revolving credit facility was terminated. As a result, CPPL accelerated the amortization of $1.4 million of deferred costs associated with the revolving credit facility, which is included in interest expense for the year ended December 31, 2016 .

CPG Commercial Paper Program. CPG's commercial paper program (the "Program") had a Program limit of up to $1,000.0 million . CEG, OpCo GP and Columbia OpCo 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. As of December 31, 2015 , CPG had no promissory notes outstanding under the Program. On June 30, 2016, in anticipation of the Merger, the Program was terminated. CPG had no promissory notes outstanding under the Program at the time of termination.

Given their maturity and turnover is three months or less, cash flows related to the borrowings and repayments of the CPG and CPPL revolving credit facilities and the Program are presented net in the Statements of Consolidated and Combined Cash Flows.

6.	Long-Term Debt

Senior notes issuance. On May 22, 2015 , CPG issued a private placement of $2,750.0 million in aggregate principal amount of senior notes, comprised of $500.0 million of 2.45% senior notes due 2018 (the "2018 Notes"), $750.0 million of 3.30% senior notes due 2020 (the "2020 Notes"), $1,000.0 million of 4.50% senior notes due 2025 (the "2025 Notes") and $500.0 million of 5.80% senior notes due 2045 (the “2045 Notes” and, together with the 2018 Notes, 2020 Notes and 2025 Notes, the “Notes”).

The initial Guarantors are three subsidiaries of CPG, CEG, Columbia OpCo and OpCo GP. The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all of the Guarantors. Each guarantee of CPG’s obligations under

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the Notes is a direct, unsecured and unsubordinated obligation of the applicable Guarantor and has the same ranking with respect to indebtedness of that Guarantor as the Notes have with respect to CPG’s indebtedness.

The guarantees of any Guarantor may be released under certain circumstances. First, if CPG discharges or defeases its obligations with respect to the Notes of any series, 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 the Notes.

The Indenture governing the Notes, dated as of May 22, 2015, contains covenants that, among other things, limit the ability of CPG and certain of its subsidiaries to incur liens, to enter into sale and lease-back transactions and to enter into mergers, consolidations or transfers of all or substantially all of their assets. The Indenture also contains customary events of default.

The 2018 Notes will mature on June 1, 2018 , the 2020 Notes will mature on June 1, 2020 , the 2025 Notes will mature on June 1, 2025 and the 2045 Notes will mature on June 1, 2045 . Interest on the Notes of each series will be payable semi-annually in arrears on June 1 and December 1.

On February 23, 2016, CPG filed an exchange offer registration statement with the SEC. The registration statement was declared effective as of April 14, 2016. The exchange offer contemplated by the registration statement expired on May 12, 2016. A post-effective amendment to the registration statement was filed on January 30, 2017 to terminate the registration of any senior notes under the registration statement that remained unexchanged.

The following table summarizes the aggregate maturities of long-term debt outstanding as of December 31, 2016 :

Year Ending December 31, (in millions)
2017	$	—
2018	500.0
2019	—
2020	750.0
2021	—
After	1,500.0
Total (1)	$	2,750.0

⁽¹⁾ This amount excludes unamortized discount and unamortized debt issuance costs of $3.4 million and $18.0 million , respectively. The unamortized discount and unamortized debt issuance costs applicable to the Notes are being amortized over the weighted average life of the Notes.

7.    Gain on Sale of Assets

CPG recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. For the years ended December 31, 2016 , 2015 and 2014 , gains on conveyances amounted to $16.9 million , $52.3 million and $34.5 million , respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $9.0 million and $35.8 million received by CEVCO during the years ended December 31, 2016 and 2015 , respectively, 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, 2016 and 2015 , deferred gains of approximately $0.3 million and $8.1 million , respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated Balance Sheets.

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8.	Property, Plant and Equipment

CPG’s property, plant and equipment on the Consolidated Balance Sheets are classified as follows:  

At December 31, (in millions)	2016				2015
Property, plant and equipment
Pipeline and other transmission assets	$	6,681.2			$	6,160.4
Storage facilities	1,415.3				1,370.1
Gas stored base gas	299.5				299.5
Gathering and processing facilities	566.9				370.2
Construction work in process	1,097.0				487.6
General plant, software, and other assets	401.3				364.5
Property, plant and equipment	10,461.2				9,052.3
Accumulated depreciation and amortization	(3,126.2		)		(2,988.6		)
Net property, plant and equipment	$	7,335.0			$	6,063.7

The table below lists CPG's applicable annual depreciation rates:

	Year Ended December 31,
	2016		2015		2014
Depreciation rates
Pipeline and other transmission assets	1.00% - 2.50%		1.00% - 2.50%		1.00% - 2.50%
Storage facilities	2.19% - 3.00%		2.19% - 3.00%		2.19% - 3.30%
Gathering and processing facilities	1.67% - 2.50%		1.67% - 2.50%		1.67% - 2.50%
General plant, software, and other assets	1.00% - 20.00%		1.00% - 21.00%		1.00% - 10.00%

9.	Goodwill

CPG 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 CPG's goodwill relates to NiSource's acquisition of CEG in 2000, which was contributed to CPG prior to the Separation. CPG's goodwill assets at December 31, 2016 and December 31, 2015 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 the carrying value, indicating that no impairment existed.

In estimating the fair value of Columbia Gas Transmission Operations for the May 1, 2012 test, the Predecessor used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for 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. Under the market approach, the Predecessor utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer

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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 Predecessor 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.

CPG applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2016. For the current year test, CPG 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 recent Merger Agreement and acquisition price were incorporated into the current year testing. 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.

CPG 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. In consideration of all relevant factors, there were no indicators that would require goodwill impairment testing subsequent to May 1, 2016.

10.	Asset Retirement Obligations

Changes in CPG’s liability for asset retirement obligations for the years 2016 and 2015 are presented in the table below:

(in millions)	2016				2015
Beginning Balance	$	25.7			$	23.2
Accretion expense	1.1				1.2
Additions	—				4.1
Change in estimated cash flows	(6.0		)		(2.8		)
Ending Balance	$	20.8			$	25.7

CPG's 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. CPG 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.

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11.	Regulatory Matters

Regulatory Assets and Liabilities

Current and noncurrent regulatory assets and liabilities were comprised of the following items:

At December 31, (in millions)	2016				2015
Assets
Unrecognized pension benefit and other postretirement benefit costs	$	111.3			$	135.2
Other postretirement costs	6.3				9.0
Deferred taxes on AFUDC equity	57.0				35.4
Other	2.3				3.1
Total Regulatory Assets	$	176.9			$	182.7

 

At December 31, (in millions)	2016				2015
Liabilities
Cost of removal	$	141.5			$	154.7
Regulatory effects of accounting for income taxes	10.2				10.6
Modernization revenue sharing	7.4				—
Other postretirement costs	134.3				155.6
Other	—				1.9
Total Regulatory Liabilities	$	293.4			$	322.8

No regulatory assets are earning a return on investment at December 31, 2016 . Regulatory assets of $58.9 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 6 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. CPG is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized.

Liabilities:

Cost of removal - Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of 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 property.

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Modernization revenue sharing - Represents amounts related to the revenue sharing mechanism within the Columbia Gas Transmission modernization program. The revenue sharing mechanism requires Columbia Gas Transmission to share 75% of specified revenues in excess of an annual threshold.

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 CPG'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 Columbia Gas Transmission Customer Settlement (the "MOD I Settlement"). In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the MOD I 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 MOD I Settlement with firm customers included an initial five-year term with provisions for potential extensions thereafter.

The MOD I 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 MOD I 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 31, 2017, Columbia Gas Transmission received FERC approval of its December 2016 filing to recover costs associated with the fourth year of its comprehensive system modernization program. In 2016, Columbia Gas Transmission placed approximately $330.0 million in modernization investments into service, bringing the total gross investment to approximately $1.3 billion over the four year period. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

On March 17, 2016, Columbia Gas Transmission received approval from the Commission of its December 18, 2015 filing for the Modernization II Settlement (the "MOD II Settlement"). The MOD II Settlement continues a rate mechanism that was designed to enable Columbia Gas Transmission to recover costs associated with a multi-year modernization program focused on replacing, rehabilitating and/or rebuilding critical pipeline infrastructure and ensuring the safety and reliability of the Columbia Gas Transmission system.

The MOD II Settlement preserves and extends the core elements of the MOD I Settlement between Columbia Gas Transmission and its shippers that addressed previous modernization issues on the Columbia Gas Transmission system for three additional years. Columbia Gas Transmission expects to invest approximately $1.1 billion over the three-year extension period. Among other things, the MOD II Settlement preserves the MOD I Settlement’s $60.0 million base rate reduction and extends for a second term the CCRM that allows Columbia Gas Transmission to make annual limited filings under Section 4 of the Natural Gas Act to charge an additive capital demand rate in order to recover the revenue requirement related to certain eligible projects.

The MOD II Settlement includes an additional reduction in base rates equal to approximately $8.4 million annually effective as of January 1, 2016, discontinuing the collection of OPEB costs no longer required because of the substantial over-recovered position, and a further base rate reduction equal to approximately $12.4 million annually for a 6-year period also beginning January

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1, 2016, which basically refunds amounts to customers as a result of the over-collection of OPEB costs. Columbia Gas Transmission's base rates will reset effective February 1, 2019, without the need for a rate case, and a simultaneous reduction in those base rates equal to $7.5 million annually. The MOD II Settlement includes a one-time $5.0 million settlement payment effective after FERC’s approval of the 5th year CCRM for recovery under the first phase; payment would not be expected until 2018, and a revenue sharing mechanism, which requires Columbia Gas Transmission to share 50.0% of specified revenues in excess of an annual threshold. Columbia Gas Transmission has agreed to maintain a transmission depreciation rate of 1.5% , a storage depreciation rate of 2.2% , a negative salvage rate of zero percent and a moratorium through January 31, 2022 to changes in Columbia Gas Transmission’s base rates. The MOD II Settlement includes specified storage projects as eligible facilities whereby Columbia Gas Transmission may undertake construction of additional eligible facility projects in 2016-2017, with cost recovery on those projects beginning in 2019.

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 filed a cost and revenue study with the 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. On June 13, 2016, the FERC trial staff, Columbia Gulf, and all of the active parties filed a Joint Motion to Suspend the Procedural Schedule and Waive Answer Period (the "Motion"). The Motion represents that the parties unanimously support the Motion and requested waiver of the answer period, which was granted. The parties reached an agreement in principle during a June 2, 2016 settlement conference that would fully resolve all matters set for hearing by the FERC. The Motion represents that the parties expect to file an offer of settlement memorializing the agreement in principle no later than July 29, 2016, and suspension of the procedural schedule will promote an efficient and speedy resolution of this matter by allowing the participants to focus their efforts on drafting the necessary settlement documents. Columbia Gulf filed the offer of settlement with the FERC in accordance with the agreement noted above.

On August 15, 2016, the administrative law judge issued a Certification of Uncontested Settlement, which noted that no parties objected to the provisions in the offer of settlement. On September 22, 2016, the FERC issued an order approving the uncontested settlement, which requires a reduction in Columbia Gulf’s daily maximum recourse rate and addresses Columbia Gulf’s treatment of postretirement benefits other than pensions, pension expenses, and regulatory expenses. The order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020. Other terms of the settlement are included in FERC Docket No. RP16-302-000.

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.

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.

12.	Equity Method Investments

Certain investments of CPG are accounted for under the equity method of accounting. These investments are recorded within "Unconsolidated Affiliates" on CPG's Consolidated Balance Sheets and CPG's portion of the results is reflected in "Equity Earnings in Unconsolidated Affiliates" on CPG's Statements of Consolidated and Combined Operations. In the normal course of business, CPG engages in various transactions with these unconsolidated affiliates. CPG billed approximately $10.5 million and $13.1 million to Millennium Pipeline for services and other costs during the years ended December 31, 2016 and 2015 , respectively. These investments are integral to CPG's business. Contributions are made to these equity investees to fund CPG's share of projects.

 

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The following is a list of CPG's equity method investments at December 31, 2016 :

Investee	Type of Investment	% of Voting Power or Interest Held
Hardy Storage Company, LLC	LLC Membership	50.0	%
Pennant Midstream, LLC	LLC Membership	47.0	%
Millennium Pipeline Company, L.L.C.	LLC Membership	47.5	%

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As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in aggregate, material to CPG's business, the following table contains condensed summary financial data.

Year Ended December 31, (in millions)	2016				2015				2014
Millennium Pipeline
Statement of Income Data:
Net Revenues	$	205.0			$	206.3			$	190.5
Operating Income	138.1				136.1				128.8
Net Income	102.5				98.0				89.6
Balance Sheet Data:
Current Assets	34.8				35.7				32.1
Noncurrent Assets	969.8				987.1				1,016.3
Current Liabilities	48.0				44.4				42.6
Noncurrent Liabilities	497.2				535.8				568.3
Total Members’ Equity	459.4				442.6				437.5
Contribution/Distribution Data: (1)
Contributions to Millennium Pipeline	6.2				1.4				2.6
Distribution of earnings from Millennium Pipeline	48.9				47.5				35.6
Hardy Storage
Statement of Income Data:
Net Revenues	$	23.5			$	23.4			$	23.6
Operating Income	15.7				15.3				16.1
Net Income	11.2				10.3				10.6
Balance Sheet Data:
Current Assets	10.3				12.1				12.0
Noncurrent Assets	151.3				155.5				157.4
Current Liabilities	17.2				19.3				17.1
Noncurrent Liabilities	57.5				68.5				77.4
Total Members’ Equity	86.9				79.8				74.9
Contribution/Distribution Data: (1)
Contributions to Hardy Storage	—				—				—
Distribution of earnings from Hardy Storage	2.0				2.6				2.2
Pennant
Statement of Income Data:
Net Revenues	$	38.2			$	34.6			$	8.5
Operating Income (Loss)	21.2				17.8				(2.4		)
Net Income (Loss)	21.2				17.8				(2.4		)
Balance Sheet Data:
Current Assets	9.8				11.0				23.7
Noncurrent Assets	384.0				389.6				380.0
Current Liabilities	3.5				8.4				8.6
Total Members’ Equity	390.3				392.2				395.1
Contribution/Distribution Data: (1)
Contributions to Pennant	—				—				66.6
Distribution of earnings from Pennant	10.6				7.1				—
Return of capital from Pennant	2.2				16.0				—

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

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13.	Income Taxes

The components of income tax expense were as follows:

Year Ended December 31, (in millions)	2016				2015				2014
Income Taxes
Current
Federal	$	(55.7	)		$	12.1			$	19.5
State	4.2				9.1				7.6
Total Current	(51.5		)		21.2				27.1
Deferred
Federal	116.3				120.2				119.2
State	13.0				11.6				23.5
Total Deferred	129.3				131.8				142.7
Deferred Investment Credits	—				—				(0.1		)
Total Income Taxes	$	77.8			$	153.0			$	169.7

Total income taxes from continuing operations were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:

Year Ended December 31, (in millions)	2016							2015							2014
Book income from Continuing Operations before income taxes	$	231.5						$	460.5						$	438.4
Tax expense at statutory federal income tax rate	81.0				35.0	%		161.2				35.0	%		153.5				35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	11.2				4.8			13.4				2.9			20.3				4.6
Noncontrolling interest	(13.0		)		(5.6	)		(14.0		)		(3.0	)		—				—
AFUDC-Equity	(11.2		)		(4.8	)		(9.2		)		(2.0	)		(3.7		)		(0.8	)
Transaction cost	8.7				3.8			—				—			—				—
Other, net	1.1				0.4			1.6				0.3			(0.4		)		(0.1	)
Total Income Taxes	$	77.8			33.6	%		$	153.0			33.2	%		$	169.7			38.7	%

The effective income tax rates were 33.6% , 33.2% and 38.7% in 2016 , 2015 and 2014 , respectively. The overall effective tax rates in 2016 and 2015 are comparable. The 5.5% decrease in the overall effective tax rate in 2015 versus 2014 was primarily due to income received following CPPL’s IPO that is not subject to income tax at the partnership level, as well as state income taxes, utility rate making and other permanent book-to-tax differences.

On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015 (PATH). PATH, among other things, permanently extends and modifies the research credit under Internal Revenue Code Section 41, and extends bonus depreciation (additional first-year depreciation) under a phase-down through 2019, as follows:

•	At 50% for 2015-2017;

•	At 40% in 2018; and

•	At 30% in 2019.

In general, 50% bonus depreciation is available for qualified property placed in service in 2015, and in the following years, using the percentages above. CPG recorded the bonus depreciation effects of PATH for 2015 in the fourth quarter 2015. The permanent extension of the research credit did not have a significant effect on net income.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

In March 2016, the FASB issued ASU 2016-09,  Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.  Among other provisions, the standard requires that all income tax effects of awards are recognized in the income statement when the awards vest or are settled and also allows an employer to make a policy election to account for forfeitures as they occur. CPG is required to adopt ASU 2016-09 for periods beginning after December 15, 2016, including interim periods, with early adoption permitted if all of the amendments are adopted in the same period. Each amendment has varying transition requirements. CPG expects to adopt ASU 2016-09 in the first quarter of 2017. Upon adoption, CPG will record a $9.9 million increase to beginning retained earnings with a corresponding increase in deferred tax assets representing the excess tax benefits generated in years prior to adoption of ASU 2016-09.  Prior to the adoption of ASU 2016-09, CPG was precluded from recording this increase in deferred tax assets due to having a cumulative net operating loss carryforward for Federal income taxes.

In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of accumulated deferred income taxes on the balance sheet. ASU 2015-17 eliminated the requirement to separate deferred tax liabilities and assets into a current amount and a noncurrent amount on the balance sheet. ASU 2015-17 simplifies the presentation of ADIT by requiring ADIT liabilities and ADIT assets be classified as noncurrent on the balance sheet. The FASB decided that the amendments in ASU 2015-17 can be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The update is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016 and earlier application is permitted. CPG elected early adoption of ASU 2015-17 in December 2015. The December 31, 2016 and 2015 accumulated deferred income taxes are presented with application of ASU 2015-17, and are presented on the Consolidated Balance Sheet as a noncurrent liability.

Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

The principal components of CPG’s net deferred tax liability were as follows:

At December 31, (in millions)	2016				2015
Deferred tax liabilities
Accelerated depreciation and other property differences	$	1,625.8			$	1,429.2
Pension and other postretirement/postemployment benefits	31.1				29.9
Other regulatory assets	67.8				71.8
Equity method investments	130.2				124.3
Total Deferred Tax Liabilities	1,854.9				1,655.2
Deferred tax assets
Other regulatory liabilities	(104.9		)		(126.8		)
Net operating loss carryforward	(231.7		)		(141.4		)
Other	(17.9		)		(38.9		)
Total Deferred Tax Assets	(354.5		)		(307.1		)
Net Deferred Tax Liabilities	$	1,500.4			$	1,348.1

State income tax net operating loss benefits for West Virginia were recorded at their full value which CPG anticipates it is more likely than not that it will realize these benefits, prior to their expiration. The $211.5 million Federal net operating loss benefit carryforward will expire in various tax years from 2030 through 2036 and the $20.2 million state net operating loss benefit carryforward will expire in various tax years from 2028 through 2036 .

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is zero for December 31, 2016 , a $0.4 million decrease for December 31, 2015 and zero for December 31, 2014 . CPG recognizes accrued interest on

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unrecognized tax benefits, accrued interest on other income tax liabilities, and tax penalties in income tax expense. No material amounts were recorded for the years ended December 31, 2016 , 2015 and 2014 , respectively.

CPG is subject to income taxation in the United States and various state jurisdictions, primarily Indiana, West Virginia, Virginia, Pennsylvania, Kentucky, Louisiana, Mississippi, Maryland, Tennessee, New Jersey and New York.

CPG was included in NiSource’s consolidated federal return prior to its separation from NiSource on July 1, 2015. Because NiSource is part of the IRS's Large and Mid-Size Business program, each year's federal income tax return is typically audited by the IRS. As of December 31, 2016 , federal income tax years through 2015 for NiSource have been audited and are effectively closed to further assessment.

The statute of limitations in each of the state jurisdictions in which CPG operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2016 , there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

Subsequent to the Merger, CPG is included in the consolidated Federal income tax return filed by US Parent and is a party to a Federal Tax Allocation Agreement with US Parent. The tax allocation agreement allocates to CPG an amount of Federal income tax liabilities and benefits similar to that which would be if CPG had filed a separate return. For states that require consolidated or combined returns, CPG will be included with certain TransCanada affiliates and will settle its state income tax liabilities and benefits with US Parent.

14.	Pension and Other Postretirement Benefits

CPG provides defined contribution plans and noncontributory defined benefit retirement plans ("the CPG Plans") that cover its employees. 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. The majority of employees may become eligible for these benefits if they reach retirement age while working for CPG. The expected cost of such benefits is accrued during the employees’ years of service. Current rates charged to customers of CPG include postretirement benefit costs. Cash contributions are remitted to tax-qualified trusts.

Prior to the Separation, CPG was a participant in the consolidated NiSource defined benefit retirement plans and was allocated a ratable portion of NiSource's tax-qualified trusts for the plans in which its employees and retirees participated. As a result, CPG followed multiple employer accounting under the provisions of GAAP. As of July 1, 2015, in connection with the Separation, accrued pension and postretirement benefit obligations for CPG participants and related plan assets were transferred to CPG. CPG continues to follow multiple employer accounting following the Separation.

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. 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.

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.

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In 2016, a revised asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status (as measured by the projected benefit obligation of the qualified pension plan divided by the market value of qualified pension plan assets) increases. 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, 2016 are as follows:

Asset Mix Policy of Funds:

	Defined Benefit Pension Plan				Postretirement Benefit Plan
Asset Category	Minimum		Maximum		Minimum		Maximum
Domestic Equities	35%		55%		35%		55%
International Equities	10%		20%		15%		25%
Fixed Income	30%		50%		20%		50%
Short-Term Investments	0%		10%		0%		10%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2016 and December 31, 2015 :

December 31, 2016	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	$	148.7			42.7	%		$	95.9			41.5	%
International Equities	56.3				16.2	%		43.4				18.8	%
Fixed Income	136.3				39.2	%		76.9				33.2	%
Cash/Other	6.8				1.9	%		15.1				6.5	%
Total	$	348.1			100.0	%		$	231.3			100.0	%
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	$	141.0			39.4	%		$	101.6			44.4	%
International Equities	62.5				17.5	%		42.8				18.8	%
Fixed Income	123.3				34.4	%		76.6				33.6	%
Cash/Other	31.0				8.7	%		7.2				3.2	%
Total	$	357.8			100.0	%		$	228.2			100.0	%

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

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, 2016 and 2015 . 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 as of December 31, 2016 and December 31, 2015 .

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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.

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.

Net Asset Value Measurements

Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are measure at net asset value. 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.

For the year ended December 31, 2016 , there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets.

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Fair Value Measurements at December 31, 2016 :

Fair Value Measurements (in millions)	December 31, 2016				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	$	0.2			$	0.2			$	—			$	—
Fixed income securities
Government	8.8				—				8.8				—
Corporate	19.5				—				19.5				—
Commingled funds
Short-term money markets (2)	6.6
U.S. equities (2)	93.1
International equities (2)	56.3
Fixed income (2)	73.2
Mutual funds
U.S. equities	55.6				55.6				—				—
Fixed income	34.8				34.8				—				—
Pension plan assets subtotal	348.1				90.6				28.3				—
Other postretirement benefit plan assets
Cash	0.4				0.4				—				—
Commingled funds
Short-term money markets (2)	14.7
U.S. equities (2)	1.0
Mutual funds
U.S. equities	94.9				94.9				—				—
International equities	43.4				43.4				—				—
Fixed income	76.9				76.9				—				—
Other postretirement benefit plan assets subtotal	231.3				215.6				—				—
Due to brokers, net (1)	(0.2		)
Accrued investment income/dividends	0.6
Total pension and other postretirement benefit plan assets	$	579.8			$	306.2			$	28.3			$	—

⁽¹⁾ This class represents pending trades with brokers.

⁽²⁾ This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2016:

(in millions)	Fair Value				Unfunded Commitments				Redemption Frequency		Redemption Notice Period
Commingled Funds
Short-term money markets	$	21.3			$	—			Daily		1 day
U.S. equities	94.1				—				Daily		1 day
International equities	56.3				—				Daily		2 days
Fixed income	73.2				—				Daily		2-3 days
Total	$	244.9			—

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Fair Value Measurements at December 31, 2015 :

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	$	0.9			$	0.9			$	—			$	—
Equity securities
International equities	6.6				6.6				—				—
Fixed income securities
Government	8.5				—				8.5				—
Corporate	13.0				—				13.0				—
Commingled funds
Short-term money markets (2)	31.1
U.S. equities (2)	141.0
International equities (2)	55.6
Fixed income (2)	100.9
Pension plan assets subtotal	357.6				7.5				21.5				—
Other postretirement benefit plan assets
Commingled funds
Short-term money markets (2)	7.3
U.S. equities (2)	13.9
Mutual funds
U.S. equities	87.7				87.7				—				—
International equities	42.8				42.8				—				—
Fixed income	76.5				76.5				—				—
Other postretirement benefit plan assets subtotal	228.2				207.0				—				—
Due to brokers, net (1)	(0.4		)
Accrued investment income/dividends	0.6
Total pension and other postretirement benefit plan assets	$	586.0			$	214.5			$	21.5			$	—

⁽¹⁾ This class represents pending trades with brokers.

⁽²⁾ This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.

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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, 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	8.5				—				—				—				—				(8.5		)		—
International multi-strategy	5.3				—				—				—				—				(5.3		)		—
Distressed opportunities	1.1				—				—				—				—				(1.1		)		—
Real estate	2.6				—				—				—				—				(2.6		)		—
Total	$	17.6			$	—			$	—			$	—			$	—			$	(17.6	)		$	—

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

The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2015:

(in millions)	Fair Value				Unfunded Commitments				Redemption Frequency		Redemption Notice Period
Commingled Funds
Short-term money markets	$	38.4			$	—			Daily		1 day
U.S. equities	154.9				—				Monthly		3 days
International equities	55.6				—				Monthly		14-30 days
Fixed income	100.9				—				Monthly		3 days
Total	$	349.8			$	—

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Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure . The following table provides a reconciliation of the plans’ funded status and amounts reflected in CPG’s Consolidated Balance Sheets at December 31 based on a December 31 measurement date:

	Pension Benefits								Other Postretirement Benefits
(in millions)	2016				2015				2016				2015
Change in projected benefit obligation (1)
Benefit obligation at beginning of year	$	404.5			$	397.6			$	112.1			$	124.2
Service cost	6.4				5.9				0.9				1.0
Interest cost	15.1				15.0				4.5				4.7
Plan participants’ contributions	—				—				2.8				2.3
Actuarial (gain) loss	(4.7		)		(6.9		)		2.1				(12.4		)
Settlement loss	3.2				—				—				—
Benefits paid	(48.8		)		(29.7		)		(13.6		)		(9.8		)
Estimated benefits paid by incurred subsidy	—				—				0.3				0.3
Transfer of participant balances from NiSource plans (2)	—				22.6				—				1.8
Projected benefit obligation at end of year	$	375.7			$	404.5			$	109.1			$	112.1
Change in plan assets
Fair value of plan assets at beginning of year	$	357.8			$	351.0			$	228.2			$	223.8
Actual return on plan assets	30.7				1.2				13.6				(2.5		)
Employer contributions	8.4				20.0				0.3				13.5
Plan participants’ contributions	—				—				2.8				2.3
Benefits paid	(48.8		)		(29.7		)		(13.6		)		(9.8		)
Transfer of participant balances from NiSource plans (2)	—				15.3				—				0.9
Fair value of plan assets at end of year	$	348.1			$	357.8			$	231.3			$	228.2
Funded status at end of year	$	(27.6	)		$	(46.7	)		$	122.2			$	116.1
Amounts recognized in the balance sheet consist of:
Noncurrent assets	$	—			$	—			$	122.2			$	116.1
Current liabilities	—				(0.8		)		—				—
Noncurrent liabilities	(27.6		)		(45.9		)		—				—
Net amount recognized at end of year (3)	$	(27.6	)		$	(46.7	)		$	122.2			$	116.1
Amounts recognized in AOCI or regulatory assets/liabilities (4)
Unrecognized prior service credit	$	(2.6	)		$	(3.7	)		$	(1.3	)		$	(2.0	)
Unrecognized actuarial loss (gain)	133.0				164.5				(0.7		)		(3.9		)
Total recognized AOCI or regulatory assets/liabilities	$	130.4			$	160.8			$	(2.0	)		$	(5.9	)

⁽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 transfer of additional pension and OPEB plan participants to CPGSC upon Separation from NiSource that were determined in the current year.

⁽³⁾ CPG recognizes in its Consolidated Balance Sheets the underfunded and overfunded status of its various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.

⁽⁴⁾ CPG determined that the future recovery of pension and other postretirement benefits costs is probable. CPG recorded regulatory assets and liabilities of $111.3 million and zero , respectively, as of December 31, 2016 , and $135.2 million and $0.7 million , respectively, as of December 31, 2015 that would otherwise have been recorded to accumulated other comprehensive loss.

CPG’s accumulated benefit obligation for its pension plans was $375.7 million and $404.5 million as of December 31, 2016 and 2015 , 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.

CPG's pension plans were underfunded by $27.6 million at December 31, 2016 , compared to being underfunded by $46.7 million at December 31, 2015 . The improvement in funded status is primarily due to the return on plan assets. CPG contributed $8.4 million and $20.0 million to its pension plans in 2016 and 2015 , respectively.

During 2016 , CPG’s funded status for its other postretirement benefit plans improved by $6.1 million to an overfunded status of $122.2 million primarily due to the return on plan assets, offset by a decrease in the discount rates in 2016 compared to 2015. CPG

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contributed approximately $0.3 million and $13.5 million to its other postretirement benefit plans in 2016 and 2015 , respectively. No amounts of CPG’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG or any of its subsidiaries in 2017 .

In 2016, CPG's pension plans had year to date lump sum payouts exceeding the plans' 2016 service cost plus interest cost due to Merger related payouts as well as the non-qualified pension plan being terminated in connection with the Merger. As a result, settlement accounting was required and CPG recorded a settlement charge of $12.3 million for the year ended December 31, 2016.

The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for CPG’s various plans as of December 31:

	Pension Benefits						Other Postretirement  Benefits
	2016			2015			2016			2015
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate	4.10	%		4.05	%		4.25	%		4.29	%
Rate of Compensation Increases	2.50	%		4.00	%
Health Care Trend Rates
Trend for Next Year							8.47	%		8.39	%
Ultimate Trend							4.50	%		4.50	%
Year Ultimate Trend Reached							2024			2022

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	2.6				(2.4		)

CPG expects to make contributions of zero dollars to its pension plan and approximately $1.9 million to its postretirement medical and life plans in 2017 .

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 CPG'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)
2017	$	32.3			$	7.8			$	0.5
2018	33.1				7.8				0.5
2019	33.8				7.8				0.4
2020	35.2				7.7				0.4
2021	34.9				7.6				0.4
2022-2026	168.8				35.5				1.2

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended December 31, 2016 , 2015 and 2014 :

	Pension Benefits												Other Postretirement Benefits
(in millions)	2016				2015				2014				2016				2015				2014
Components of Net Periodic Benefit Cost (Income)
Service cost	$	6.4			$	5.9			$	4.8			$	0.9			$	1.0			$	1.1
Interest cost	15.1				15.0				15.7				4.5				4.7				4.6
Expected return on assets	(25.0		)		(28.2		)		(27.3		)		(15.0		)		(18.1		)		(16.6		)
Amortization of prior service (credit) cost	(1.2		)		(1.1		)		(1.1		)		(0.7		)		(0.3		)		0.1
Recognized actuarial loss (gain)	12.2				9.9				7.5				0.3				(0.3		)		—
Net Periodic Benefit Cost (Income)	7.5				1.5				(0.4		)		(10.0		)		(13.0		)		(10.8		)
Additional loss recognized due to:
Settlement loss	12.3				—				—				—				—				—
Total Net Periodic Benefit Cost (Income)	$	19.8			$	1.5			$	(0.4	)		$	(10.0	)		$	(13.0	)		$	(10.8	)

The $18.3 million increase in the actuarially-determined pension benefit cost (income) is due primarily to the settlement charge and a decrease in the expected return on plan assets in 2016 compared to 2015 . For its other postretirement benefit plans, CPG recognized $10.0 million in net periodic benefit income in 2016 compared to net periodic benefit income of $13.0 million in 2015 due primarily to a decrease in the expected return on plan assets in 2016 compared to 2015 .

The following table provides the key assumptions that were used to calculate the net periodic benefits cost for CPG's various plans:

 

	Pension Benefits									Other Postretirement Benefits
	2016			2015			2014			2016			2015			2014
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount Rate	3.90	%		3.84	%		4.34	%		4.12	%		4.10	%		4.76	%
Expected Long-Term Rate of Return on Plan Assets	7.29	%		8.20	%		8.30	%		6.81	%		8.05	%		8.14	%
Rate of Compensation Increases	4.00	%		4.00	%		4.00	%

CPG believes it is appropriate to assume an 7.29% and 6.81% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2016 pension benefits cost. This is primarily based on asset mix and historical rates of return.

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The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:

	Pension Benefits								Other Postretirement Benefits
(in millions)	2016				2015				2016				2015
Other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory assets or liabilities
Settlements	$	(12.3	)		$	—			$	—			$	—
Net actuarial (gain) loss	(7.1		)		25.6				3.5				8.6
Less: amortization of prior service cost	1.2				1.1				0.7				0.3
Less: amortization of net actuarial (gain) loss	(12.2		)		(9.9		)		(0.3		)		0.3
Total recognized in other comprehensive income or regulatory assets or liabilities	$	(30.4	)		$	16.8			$	3.9			$	9.2
Amount recognized in net periodic benefit cost and other comprehensive income or regulatory assets or liabilities	$	(10.6	)		$	18.3			$	(6.1	)		$	(3.8	)

Based on a December 31, 2016 measurement date, the net unrecognized actuarial (gain) loss, unrecognized prior service cost, and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2017 for the pension plans are $10.0 million , $(1.2) million and zero , respectively, and for other postretirement benefit plans are $0.5 million , $(0.7) million and zero , respectively.

15.	Fair Value

CPG 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. CPG’s long-term debt 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 . The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2016 and 2015 , 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 2016 (1)				Estimated Fair Value 2016				Carrying Amount 2015 (1)				Estimated Fair Value 2015
Long-term debt	$	2,750.0			$	2,868.8			$	2,750.0			$	2,592.1

⁽¹⁾ The carrying amount of the Notes differs from the Long-term debt balance on the Consolidated Balance Sheets due to the related unamortized discount and unamortized debt issuance costs, both of which are being amortized over the weighted average life of the Notes.

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16.	Share-Based Compensation

Prior to the Separation, CPG employees participated in NiSource's Omnibus Incentive Plan (the "NiSource Plan") and had outstanding awards under the NiSource Director Stock Incentive Plan (“NiSource Director Plan”), which was terminated in 2010. Upon the Separation, outstanding CPG employee restricted stock units, performance units and employee director awards previously issued under the NiSource Plan and NiSource Director Plan were adjusted and converted into new CPG share-based awards under the Columbia Pipeline Group, Inc. 2015 Omnibus Incentive Plan (the "Omnibus Plan") using a formula designed to preserve the intrinsic value and fair value of the awards immediately prior to the Separation. The performance targets applicable to the performance units were frozen at the levels achieved as of the Separation and pro-rated to reflect the proportion of the service period completed. Under the Omnibus Plan, these awards represent restricted stock units with no performance contingencies. All adjusted awards retained the vesting schedule of the original awards.

The Omnibus Plan term began on the effective date of the Separation. The Omnibus Plan provided for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock and restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards.

On July 1, 2016, at the effective time of the Merger, each outstanding restricted stock unit, performance share and phantom unit, whether or not vested, was deemed to be fully vested (in the case of performance shares, based on performance deemed satisfied at the greater of actual performance for the relevant period and the target level of 100%), canceled and converted into the right of the holder to receive $25.50 in cash, without interest, in respect of each share of CPG common stock underlying such award.

CPG recognized stock-based employee compensation expense of $65.2 million , $7.9 million and $4.4 million , during the years ended December 31, 2016 , 2015 and 2014 , respectively, as well as related tax benefits of $21.9 million , $2.9 million and $1.6 million , respectively.

Restricted Stock Units and Restricted Stock . In 2016 , CPG granted 12,144 restricted stock units and shares of restricted stock, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was $0.2 million , based on the average market price of CPG's common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period which is generally three years. There are no restricted stock units or shares of restricted stock outstanding for the 2016 award following the effective time of the Merger.

In 2015, CPG granted 130,160 restricted stock units and shares of restricted stock, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was $3.6 million , based on the average market price of CPG’s common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period which is generally three years. There are no restricted stock units or shares of restricted stock outstanding for the 2015 award following the effective time of the Merger.

In 2015, NiSource granted restricted stock units and shares of restricted stock that were converted into 450,107 CPG restricted stock units at Separation, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was $11.6 million , based on the average market price of NiSource’s common stock at the date of each grant less the present value of any dividends not received during the vesting period converted into CPG common stock awards, which will be expensed, net of forfeitures, over the vesting period which is generally three years. There are no restricted stock units or shares of restricted stock outstanding for the 2015 NiSource award following the effective time of the Merger.

In 2014, NiSource granted restricted stock units and shares of restricted stock that were converted into 198,532 CPG restricted stock units at Separation, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was $4.2 million , based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period converted into CPG common stock awards, which will be expensed, net of forfeitures, over the vesting period which is generally three years. There are no restricted stock units or shares of restricted stock outstanding for the 2014 NiSource award following the effective time of the Merger.

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	Restricted Stock Units			Weighted Average Grant Date Fair  Value
Nonvested at December 31, 2015	2,268,792			$	18.85
Granted	12,144			16.86
Forfeited	(22,590	)		22.71
Vested	(2,258,346	)		18.80
Outstanding at December 31, 2016	—			$	—

Performance Shares . In 2016 , CPG granted 955,848 performance shares subject to performance and service conditions. The grant date fair value of the awards was $17.0 million , based on the average market price of CPG's common stock at the date of grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. There are no performance shares outstanding for the 2016 award following the effective time of the Merger.

In 2015, CPG granted 161,504 performance shares subject to performance and service conditions. The grant date fair value of the awards was $4.5 million , based on the average market price of CPG’s common stock at the date of the grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. There are no performance shares outstanding for the 2015 award following the effective time of the Merger.

In 2014, NiSource granted performance shares that were converted to 586,219 CPG restricted stock units at Separation, subject to performance and service conditions. The grant date fair value of the awards was $11.3 million , based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. Through the conversion, the performance contingencies were removed from these awards. There are no restricted stock units or shares of restricted stock outstanding for the 2014 NiSource award following the effective time of the Merger.

	Contingent Awards			Weighted Average Grant Date Fair  Value
Nonvested at December 31, 2015	161,504			$	28.16
Granted	955,848			17.79
Forfeited	—			—
Vested	(1,117,352	)		19.29
Outstanding at December 31, 2016	—			$	—

Non-employee Director Awards . Restricted stock units were granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s restricted stock units would vest on the first anniversary of the grant thereof, subject to special pro-rata vesting rules in the event of Retirement or Disability (as defined in the award agreement), or death. The vested restricted stock units were payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. There are no units outstanding following the effective time of the Merger.

Fully vested restricted stock units that remained outstanding under the NiSource Plan and NiSource Director Plan as of the Separation date were converted into CPG awards. All such awards were distributed to the directors upon their separation from CPG's board of directors. There are no restricted stock units outstanding following the effective time of the Merger.

401(k) Match, Profit Sharing and Company Contribution. CPG has a voluntary 401(k) savings plan covering eligible employees that allows for periodic discretionary matches as a percentage of each participant's contributions. CPG also has a retirement savings plan that provides for discretionary profit sharing contributions to eligible employees based on earnings results; and eligible exempt employees hired after January 1, 2013, receive a non-elective company contribution of three percent of eligible pay. For the years ended December 31, 2016 , 2015 and 2014 , CPG recognized 401(k) match, profit sharing and non-elective contribution expense of $12.2 million , $9.8 million and $8.4 million , respectively.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

17. Other Commitments and Contingencies

A. Guarantees and Indemnities.     In the normal course of business, CPG and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of 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 a parent or subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the parent or subsidiaries' intended commercial purposes. The total guarantees and indemnities in existence at December 31, 2016 and the years in which they expire were:

(in millions)	Total			2017			2018			2019			2020			2021			After
Other guarantees	$	4.7		$	2.2		$	—		$	—		$	—		$	—		$	2.5

Guarantees of Debt. Certain of CPG's subsidiaries, including OpCo GP, Columbia OpCo and CEG have guaranteed payment of $2,750.0 million in aggregated principal amount of CPG's senior notes. Each guarantor of CPG's obligations 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.

Lines and Letters of Credit. CPG maintained a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit was available. On July 1, 2016, in connection with the Merger, all existing letters of credit were migrated to a TransCanada credit facility and the CPG revolving credit facility was terminated. CPPL maintained a $500.0 million senior revolving credit facility, of which $50.0 million was available for issuance of letters of credit. On June 29, 2016, in anticipation of the Merger, all outstanding borrowings, facility fees and interest were paid in full and the revolving credit facility was terminated.

CPG's commercial paper program (the "Program") had a Progra m limit of up to $1,000.0 million . CEG, OpCo GP and Columbia OpCo 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. On June 30, 2016, in anticipation of the Merger, the Program was terminated. CPG had no promissory notes outstanding under the Program at the time of termination.

CPG maintains a $1,000.0 million revolving credit facility. CPG expects that the revolving credit facility will be utilized for the financing of capital expenditures and for CPG’s general corporate purposes, including working capital. As of December 31, 2016, CPG had no outstanding borrowings under the revolving credit facility.

Other Guarantees or Obligations. CPG has purchase and sale agreement guarantees totaling  $4.7 million , which guarantee purchaser performance or seller performance under covenants, obligations, liabilities, representations or warranties under the agreements. No amounts related to the purchase and sale agreement guarantees are reflected in the Consolidated Balance Sheets. Management believes that the likelihood CPG would be required to perform or otherwise incur any significant losses associated with any of the aforementioned guarantees is remote.

Other Legal Proceedings . In the normal course of its business, CPG has been named as a defendant in various legal proceedings. In the opinion of CPG, the ultimate disposition of these currently asserted claims will not have a material impact on CPG's consolidated financial statements.

B. Tax Matters . CPG records liabilities for potential income tax assessments. The accruals relate to tax positions in a variety of taxing jurisdictions and are based on CPG’s estimate of the ultimate resolution of these positions. These liabilities may be affected by changing interpretations of laws, rulings by tax authorities, or the expiration of the statute of limitations. CPG was included in NiSource's consolidated federal return for tax years prior to December 31, 2014 and will be included in NiSource's consolidated 2015 federal return through July 1, 2015. NiSource is part of the IRS Large and Mid-Size Business program. As a result, each year’s federal income tax return is typically audited by the IRS. As of December 31, 2016, federal income tax years through 2015 for NiSource have been audited and are effectively closed to further assessment. The statute of limitations in each of the state jurisdictions in which CPG operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2016, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

CPG is currently being audited for sales and use tax compliance in the state of Ohio and West Virginia. None of these sales and use tax audits are expected to have a material impact on the consolidated and combined financial statements.

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C. Environmental Matters . CPG’s operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and nonhazardous waste. Historically, CPG’s environmental compliance costs have not had a material adverse effect on its results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on CPG’s business and operating results.

It is CPG’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 CPG will not incur fines and penalties.

As of December 31, 2016 and 2015 , CPG has liabilities recorded of approximately $7.8 million and $8.3 million , respectively, to cover environmental remediation at various sites. The current portion of these liabilities is included in “Other accruals” in the Consolidated Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated Balance Sheets. CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. As of the date of these financial statements, these expenditures are not estimable at some sites. CPG periodically adjusts its accrual as information is collected and estimates become more refined.

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. CPG 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.

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 United States on an annual basis. In August 2016, the EPA proposed a rule revising provisions of the Prevention of Significant Deterioration ("PSD") and Title V Permitting Regulations to conform with the U.S. Supreme Court’s decision in UARG v. EPA, 134 S. Ct. 2427 (2014), and the amended judgment issued by the D.C. Circuit, in Coalition for Responsible Regulation v. EPA, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015). For instance, the August 2016 proposed rule seeks to ensure that neither the PSD nor the Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit ("PTE") GHGs above the applicable regulatory thresholds. In addition, EPA is also proposing under the rulemaking a significant emissions rate ("SER") of 75,000 tons per year carbon dioxide equivalent for GHGs under the PSD program that would establish an appropriate threshold level below which Best Available Control Technology ("BACT") is not required for a source’s GHG emissions. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.

New Source Performance Standards : In August 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. In May 2016, the EPA finalized the rule to regulate fugitive methane emissions in the natural gas transmission and storage sector. The final rule was subsequently published in the Federal Register on June 3, 2016. CPG is working with industry groups to litigate the delay of repair criteria in the Final Rule and to clarify ambiguities within the rule. Currently, CPG's facilit ies are not impacted by this rule. New or modified sources installed in subsequent years will be impacted by this rule at a cost of approximately $30,000 /site/year. Based on the current capital project schedule, 16 new or modified facilities will be impacted by this rule in 2019 at a total estimated cost of $500,000 annually thereafter.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Environmental Remediation

CPG has liabilities associated with the cleanup of some of its former operations. Four sites are associated with its former propane operations and ten sites associated with former petroleum operations. The total liability related to these sites was $6.3 million and $6.5 million at December 31, 2016 and 2015 , respectively. The liability represents CPG’s best estimate of the cost to remediate the facilities.

CPG has liabilities associated with the PCB remediation of its existing facilities. The total liability related to these sites was $1.5 million and $1.8 million at December 31, 2016 and 2015 , respectively. The liability represents CPG's best estimate of the cost to remediate the facilities.

Pipeline Safety

In March 2016, the PHMSA announced a proposed rulemaking that would, if adopted, impose more stringent requirements for certain gas lines and gathering lines under varying circumstances. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond “high consequence areas” to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as 5 dwellings within the potential impact area; require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require gathering lines in Class I areas, both onshore and offshore, to comply with standards regarding damage prevention, corrosion control (for metallic pipe), public education, MAOP limits, line markers and emergency planning if such gathering lines’ nominal design is 8 inches or more. In order to provide clarity and greater certainty on what may constitute a “gathering line,” PHMSA is proposing a new definition of that term under the rulemaking, which term would now encompass “a pipeline, or a connected series of pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of the following endpoints” including the “inlet of 1 ^st gas processing plant;” the “outlet of” a gas treatment facility (not associated with a processing plant or compressor station); the “[o]utlet of the furthermost downstream compressor” leading to a pipeline, or the “point where separate production fields are commingled.” Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

On June 22, 2016, President Obama signed the 2016 Pipeline Safety Act. Extending PHMSA’s statutory mandate through 2019, the 2016 Pipeline Safety Act establishes or continues the development of stringent requirements affecting pipeline safety. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe natural gas and hazardous liquid pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. This new rule allows PHMSA to impose restrictions, prohibitions, and require safety measures without giving operators prior notice or an opportunity for a hearing. In contrast to PHMSA’s past practice of issuing Corrective Action Orders to an individual owner, operator, or facility, under the new rule PHMSA can issue an Emergency Order for numerous entities. PHMSA has until March 19, 2017 to issue a permanent final rule, when this temporary rule expires. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

D. Operating Lease Commitments. CPG leases assets in several areas of its operations. Payments made in connection with operating leases were $23.9 million in 2016 , $21.2 million in 2015 and $14.9 million in 2014 , and are primarily charged to operation and maintenance expense as incurred.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Future minimum rental payments required under operating and capital leases that have initial or remaining non-cancelable lease terms in excess of one year are:

(in millions)	Operating Leases (1)
2017	$	8.7
2018	7.4
2019	6.6
2020	6.3
2021	5.5
After	23.5
Total future minimum payments	$	58.0

⁽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.

E. Service Obligations . CPG has entered into various service agreements whereby CPG is contractually obligated to make certain minimum payments in future periods. CPG has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2017 to 2031, require CPG to pay fixed monthly charges.

On June 15, 2015 , CPG entered into a five-year IT services agreement including cloud, mobile, analytics and security technologies with IBM. The agreement became effective with the closing of the Separation on July 1, 2015 , with tiered commencement dates by service line. Under the agreement, at December 31, 2016, CPG expects to pay approximately $128.2 million to IBM in service fees as shown in the table below. Upon any termination of the agreement by CPG for any reason (other than material breach by IBM), CPG may be required to pay IBM a termination charge that could include a breakage fee, repayment of IBM's capital investments not yet recovered and IBM's wind-down expense. This termination fee could be material depending on the events giving rise to the termination and the timing of the termination.

The estimated aggregate amounts of minimum fixed payments at December 31, 2016 , were:

(in millions)	Pipeline Service Agreements				IBM Service Agreement
2017	$	67.0			$	34.3
2018	63.4				31.8
2019	55.9				31.2
2020	38.4				30.9
2021	32.2				—
After	187.0				—
Total future minimum payments	$	443.9			$	128.2

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2014 - Predecessor	$	(17.6	)		$	(8.2	)		$	(25.8	)
Other comprehensive income before reclassifications	—				(9.3		)		(9.3		)
Amounts reclassified from accumulated other comprehensive income	1.0				(0.4		)		0.6
Net current-period other comprehensive income	1.0				(9.7		)		(8.7		)
Balance as of December 31, 2014	$	(16.6	)		$	(17.9	)		$	(34.5	)
Other comprehensive income before reclassifications	(0.9		)		5.0				4.1
Amounts reclassified from accumulated other comprehensive income (2)	1.1				0.2				1.3
Net current-period other comprehensive income	0.2				5.2				5.4
Allocation of accumulated other comprehensive loss to noncontrolling interest	2.1				—				2.1
Balance as of December 31, 2015	$	(14.3	)		$	(12.7	)		$	(27.0	)
Other comprehensive income before reclassifications	—				3.7				3.7
Amounts reclassified from accumulated other comprehensive income (2)	1.3				(1.7		)		(0.4		)
Net current-period other comprehensive income	1.3				2.0				3.3
Allocation of accumulated other comprehensive loss to noncontrolling interest	0.2				—				0.2
Balance as of December 31, 2016	$	(13.2	)		$	(10.7	)		$	(23.9	)

 

⁽¹⁾ All amounts are net of tax. Amounts in parentheses indicate debits.

⁽²⁾ Includes amounts allocated to noncontrolling interest.

Equity Method Investment

During 2008, Millennium Pipeline, in which CPG 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, CPG is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss of $13.2 million , net of tax, related to these terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $13.2 million and $14.3 million at December 31, 2016 and December 31, 2015 , respectively, is included in unrealized losses on cash flow hedges above.

19.	Other, Net

Year Ended December 31, (in millions)	2016				2015				2014
AFUDC Equity	$	34.9			$	28.3			$	11.0
Miscellaneous	0.2				1.0				(2.2		)
Total Other, net	$	35.1			$	29.3			$	8.8

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20.	Interest Expense

Year Ended December 31, (in millions)	2016				2015				2014
Interest on long-term debt	$	111.0			$	67.5			$	—
Interest on short-term borrowings	0.2				1.4				—
Debt discount/cost amortization (1)	10.2				3.1				—
Allowance for funds used during construction	(5.1		)		(6.8		)		—
Other	2.8				2.4				—
Total Interest Expense (2)	$	119.1			$	67.6			$	—

⁽¹⁾ Debt discount/cost amortization for 2016 primarily consists of the accelerated amortization of $5.7 million of deferred costs associated with the CPG and CPPL revolving credit facilities. Refer to Note 5, "Short-term Borrowings" for additional information regarding the early termination of the revolving credit facilities.

⁽²⁾ Refer to Note 4, "Transactions with Affiliates" for a discussion of interest expense-affiliated for the year ended December 31, 2016 , 2015 and 2014 .

21.	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. As of December 31, 2016, TransCanada's Executive Vice President and President, Natural Gas Pipelines is the chief operating decision maker.

At December 31, 2016 , CPG's operations comprise one operating segment. CPG'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 CPG operations and determines how to allocate resources on a consolidated basis.

22. Supplemental Cash Flow Information

The following tables provide additional information regarding the CPG’s Statements of Consolidated and Combined Cash Flows for the years ended December 31, 2016 , 2015 and 2014 :

Year Ended December 31, (in millions)	2016				2015				2014
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities (1)	$	146.1			$	128.4			$	78.5
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	111.1			$	96.9			$	53.6
Cash paid for income taxes (2)	4.1				32.3				21.2

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

⁽²⁾ Cash paid for income taxes for the year ended December 31, 2015 includes $20.9 million paid to NiSource under the Tax Allocation Agreement.

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23.    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, 2016 , 2015 and 2014 . The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended December 31, 2016 , 2015 and 2014 :

Year Ended December 31,	2016							2015							2014
(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
Columbia Gas of Ohio (1)	$	169.7			12.3	%		$	167.3			12.5	%		$	168.5			12.5	%

⁽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 agreements with third parties which ultimately can decrease the net revenue amount CPG receives 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 CPG.

24.	Quarterly Financial Data (Unaudited)

(in millions)	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
2016
Total Operating Revenues	$	364.5			$	313.9			$	327.1			$	376.5
Operating Income (Loss)	151.7				91.5				(53.0		)		127.4
Income (Loss) from Continuing Operations	86.6				48.6				(49.6		)		68.1
Results from Discontinued Operations - net of taxes	0.2				—				—				—
Net Income (Loss) Attributable to CPG	72.2				38.9				(52.5		)		58.2
2015
Total Operating Revenues	$	340.0			$	316.1			$	320.9			$	357.9
Operating Income	162.7				107.3				135.9				122.2
Income from Continuing Operations	97.1				60.1				74.9				75.4
Results from Discontinued Operations - net of taxes	—				(0.3		)		(0.1		)		—
Net Income Attributable to CPG	90.0				50.8				63.0				63.4

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

25.    Condensed Consolidating Financial Statements

On May 22, 2015 , CPG closed its private placement of $2,750.0 million in aggregated principal amount of its senior notes (the "Notes"). Please see Note 6, "Long-Term Debt" for further discussion of the Notes. The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by three of CPG's subsidiaries, CEG, Columbia OpCo and OpCo GP. CEG is a 100% owned subsidiary of CPG. In lieu of providing separate financial statements for CEG, the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X have been included.

The following supplemental condensed consolidating financial information reflects CPG’s separate accounts, the combined accounts of CEG and Other Subsidiaries of CEG and CPG, including guarantors Columbia OpCo and OpCo GP, the consolidating adjustments and eliminations and the Issuer’s consolidated accounts for the dates and periods indicated. Separate financial statements have been provided for Columbia OpCo and OpCo GP based on Rule 3-10 of the SEC's Regulation S-X. For purposes of the following consolidating information, CPG’s and CEG's investment in its subsidiaries is accounted for under the equity method of accounting.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2016 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	38.8			$	30.0			$	—			$	—			$	11.1			$	—			$	79.9
Accounts receivable, net	—				0.1				—				—				194.1				—				194.2
Accounts receivable-affiliated	799.6				579.5				—				—				190.0				(1,513.3		)		55.8
Materials and supplies, at average cost	—				—				—				—				26.0				—				26.0
Exchange gas receivable	—				—				—				—				27.7				—				27.7
Deferred property taxes	—				—				—				—				61.2				—				61.2
Taxes receivable	68.6				43.6				—				—				—				(112.2		)		—
Prepayments and other	0.3				0.4				—				—				28.2				—				28.9
Total Current Assets	907.3				653.6				—				—				538.3				(1,625.5		)		473.7
Investments
Unconsolidated affiliates	—				—				—				—				446.7				—				446.7
Consolidated affiliates	5,421.1				7,482.0				6,089.2				—				—				(18,992.3		)		—
Other investments	—				—				—				—				0.8				—				0.8
Total Investments	5,421.1				7,482.0				6,089.2				—				447.5				(18,992.3		)		447.5
Property, Plant and Equipment
Property, plant and equipment	—				—				—				—				10,461.2				—				10,461.2
Accumulated depreciation and amortization	—				—				—				—				(3,126.2		)		—				(3,126.2		)
Net Property, Plant and Equipment	—				—				—				—				7,335.0				—				7,335.0
Other Noncurrent Assets
Regulatory assets	—				56.5				—				—				116.4				—				172.9
Goodwill	—				—				1,975.5				—				—				—				1,975.5
Notes receivable-affiliated	1,848.2				—				—				—				—				(1,848.2		)		—
Postretirement and postemployment benefits assets	—				0.8				—				—				121.4				(0.4		)		121.8
Deferred income taxes	—				—				—				—				84.8				(84.8		)		—
Deferred charges and other	1.7				—				—				—				9.6				—				11.3
Total Other Noncurrent Assets	1,849.9				57.3				1,975.5				—				332.2				(1,933.4		)		2,281.5
Total Assets	$	8,178.3			$	8,192.9			$	8,064.7			$	—			$	8,653.0			$	(22,551.2	)		$	10,537.7

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CONDENSED CONSOLIDATING BALANCE SHEETS (continued)

As of December 31, 2016 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
LIABILITIES, TEMPORARY EQUITY AND EQUITY
Current Liabilities
Short-term borrowings-affiliated	$	—			$	—			$	570.8			$	—			$	923.6			$	(1,494.4	)		$	—
Accounts payable	—				0.6				—				—				69.8				—				70.4
Accounts payable-affiliated	7.0				5.1				0.8				—				10.0				(18.9		)		4.0
Customer deposits	—				—				—				—				17.3				—				17.3
Taxes accrued	—				—				—				—				229.1				(112.2		)		116.9
Interest accrued	9.3				—				—				—				0.1				—				9.4
Exchange gas payable	—				—				—				—				27.2				—				27.2
Deferred revenue	—				—				—				—				3.9				—				3.9
Accrued capital expenditures	—				—				—				—				111.4				—				111.4
Accrued compensation and related costs	—				—				—				—				62.3				—				62.3
Other accruals	0.1				0.5				—				—				109.5				—				110.1
Total Current Liabilities	16.4				6.2				571.6				—				1,564.2				(1,625.5		)		532.9
Noncurrent Liabilities
Long-term debt	2,728.6				—				—				—				—				—				2,728.6
Long-term debt-affiliated	—				1,217.3				—				—				630.9				(1,848.2		)		—
Deferred income taxes	42.8				1,542.4				—				—				—				(84.8		)		1,500.4
Accrued liability for postretirement and postemployment benefits	0.7				6.4				—				—				25.5				(0.4		)		32.2
Regulatory liabilities	—				10.2				—				—				263.4				—				273.6
Asset retirement obligations	—				—				—				—				20.8				—				20.8
Other noncurrent liabilities	0.4				1.8				—				—				57.6				—				59.8
Total Noncurrent Liabilities	2,772.5				2,778.1				—				—				998.2				(1,933.4		)		4,615.4
Total Liabilities	2,788.9				2,784.3				571.6				—				2,562.4				(3,558.9		)		5,148.3
Temporary Equity
Redeemable noncontrolling interest	952.9				952.9				—				—				—				(952.9		)		952.9
Equity
Common stock	0.1				—				—				—				—				—				0.1
Additional paid-in capital	4,513.8				—				—				—				—				—				4,513.8
Accumulated deficit	(53.5		)		—				—				—												(53.5		)
Net parent investment	—				4,479.3				7,516.2				—				6,117.5				(18,113.0		)		—
Accumulated other comprehensive loss	(23.9		)		(23.6		)		(23.1		)		—				(26.9		)		73.6				(23.9		)
Total Equity	4,436.5				4,455.7				7,493.1				—				6,090.6				(18,039.4		)		4,436.5
Total Liabilities, Temporary Equity and Equity	$	8,178.3			$	8,192.9			$	8,064.7			$	—			$	8,653.0			$	(22,551.2	)		$	10,537.7

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CONDENSED CONSOLIDATING BALANCE SHEETS (continued)

As of December 31, 2015 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	800.0			$	46.7			$	1.9			$	—			$	82.3			$	—			$	930.9
Accounts receivable, net	—				5.6				—				—				146.8				—				152.4
Accounts receivable-affiliated	14.6				85.6				3.4				—				156.4				(260.0		)		—
Materials and supplies, at average cost	—				—				—				—				32.8				—				32.8
Exchange gas receivable	—				—				—				—				19.0				—				19.0
Deferred property taxes	—				—				—				—				52.0				—				52.0
Prepayments and other	0.3				10.1				—				—				43.8				(5.7		)		48.5
Total Current Assets	814.9				148.0				5.3				—				533.1				(265.7		)		1,235.6
Investments
Unconsolidated affiliates	—				—				—				—				438.1				—				438.1
Consolidated affiliates	5,174.6				7,569.8				5,608.9				—				—				(18,353.3		)		—
Other investments	12.0				0.3				—				—				1.5				—				13.8
Total Investments	5,186.6				7,570.1				5,608.9				—				439.6				(18,353.3		)		451.9
Property, Plant and Equipment
Property, plant and equipment	—				—				—				—				9,052.3				—				9,052.3
Accumulated depreciation and amortization	—				—				—				—				(2,988.6		)		—				(2,988.6		)
Net Property, Plant and Equipment	—				—				—				—				6,063.7				—				6,063.7
Other Noncurrent Assets
Regulatory assets	—				35.1				—				—				142.6				—				177.7
Goodwill	—				—				1,975.5				—				—				—				1,975.5
Notes receivable-affiliated	1,848.2				—				—				—				—				(1,848.2		)		—
Postretirement and postemployment benefits assets	—				0.5				—				—				115.6				(0.4		)		115.7
Deferred income taxes	18.9				—				—				—				—				(18.9		)		—
Deferred charges and other	4.9				—				—				—				10.6				—				15.5
Total Other Noncurrent Assets	1,872.0				35.6				1,975.5				—				268.8				(1,867.5		)		2,284.4
Total Assets	$	7,873.5			$	7,753.7			$	7,589.7			$	—			$	7,305.2			$	(20,486.5	)		$	10,035.6

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CONDENSED CONSOLIDATING BALANCE SHEETS (continued)

As of December 31, 2015 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	—			$	—			$	—			$	—			$	15.0			$	—			$	15.0
Short-term borrowings-affiliated	99.0				—				—				—				134.3				(233.3		)		—
Accounts payable	0.1				—				—				—				56.7				—				56.8
Accounts payable-affiliated	10.8				4.8				—				—				11.1				(26.7		)		—
Customer deposits	—				—				—				—				17.9				—				17.9
Taxes accrued	—				—				—				—				111.7				(5.7		)		106.0
Interest accrued	9.4				—				—				—				0.1				—				9.5
Exchange gas payable	—				—				—				—				18.6				—				18.6
Deferred revenue	—				—				—				—				15.0				—				15.0
Accrued capital expenditures	—				—				—				—				100.1				—				100.1
Accrued compensation and related costs	—				—				—				—				51.9				—				51.9
Other accruals	—				0.3				—				—				69.7				—				70.0
Total Current Liabilities	119.3				5.1				—				—				602.1				(265.7		)		460.8
Noncurrent Liabilities
Long-term debt	2,725.6				—				—				—				—				—				2,725.6
Long-term debt-affiliated	—				1,217.3				—				—				630.9				(1,848.2		)		—
Deferred income taxes	—				1,350.4				—				—				16.6				(18.9		)		1,348.1
Accrued liability for postretirement and postemployment benefits	0.3				8.3				—				—				41.2				(0.4		)		49.4
Regulatory liabilities	—				10.5				—				—				311.1				—				321.6
Asset retirement obligations	—				—				—				—				25.7				—				25.7
Other noncurrent liabilities	15.3				0.2				—				—				75.9				—				91.4
Total Noncurrent Liabilities	2,741.2				2,586.7				—				—				1,101.4				(1,867.5		)		4,561.8
Total Liabilities	2,860.5				2,591.8				—				—				1,703.5				(2,133.2		)		5,022.6
Equity
Common stock	4.0				—				—				—				—				—				4.0
Additional paid-in capital	4,032.7				—				—				—				—				—				4,032.7
Retained earnings	46.9				—				—				—				—				—				46.9
Net parent investment	—				4,232.3				7,615.4				—				5,631.3				(17,479.0		)		—
Accumulated other comprehensive loss	(27.0		)		(26.8		)		(25.7		)		—				(29.6		)		82.1				(27.0		)
Total CPG Equity	4,056.6				4,205.5				7,589.7				—				5,601.7				(17,396.9		)		4,056.6
Noncontrolling Interest	956.4				956.4				—				—				—				(956.4		)		956.4
Total Equity	5,013.0				5,161.9				7,589.7				—				5,601.7				(18,353.3		)		5,013.0
Total Liabilities and Equity	$	7,873.5			$	7,753.7			$	7,589.7			$	—			$	7,305.2			$	(20,486.5	)		$	10,035.6

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

Year Ended December 31, 2016  (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Operating Revenues
Transportation revenues	$	—			$	—			$	—			$	—			$	1,155.1			$	—			$	1,155.1
Storage revenues	—				—				—				—				196.5				—				196.5
Other revenues	—				—				—				—				30.4				—				30.4
Total Operating Revenues	—				—				—				—				1,382.0				—				1,382.0
Operating Expenses
Operation and maintenance	146.6				0.8				—				—				716.0				(0.2		)		863.2
Operation and maintenance-affiliated	3.7				—				—				—				—				(3.7		)		—
Depreciation and amortization	—				0.7				—				—				172.1				—				172.8
Gain on sale of assets	—				—				—				—				(16.6		)		—				(16.6		)
Impairment of long-lived assets	—				—				—				—				26.1				—				26.1
Property and other taxes	0.1				1.4				0.1				—				81.6				—				83.2
Total Operating Expenses	150.4				2.9				0.1				—				979.2				(3.9		)		1,128.7
Equity Earnings in Unconsolidated Affiliates	—				—				—				—				64.3				—				64.3
Equity Earnings in Consolidated Affiliates	284.0				465.2				477.9				—				—				(1,227.1		)		—
Operating Income	133.6				462.3				477.8				—				467.1				(1,223.2		)		317.6
Other Income (Deductions)
Interest expense	(121.0		)		—				—				—				(3.2		)		5.1				(119.1		)
Interest expense-affiliated	(2.1		)		(45.0		)		(3.7		)		—				(31.6		)		80.3				(2.1		)
Other, net	81.1				4.6				—				—				34.8				(85.4		)		35.1
Total Other Deductions, net	(42.0		)		(40.4		)		(3.7		)		—				—				—				(86.1		)
Income from Continuing Operations before Income Taxes	91.6				421.9				474.1				—				467.1				(1,223.2		)		231.5
Income Taxes	(62.1		)		137.8				—				—				2.1				—				77.8
Income from Continuing Operations	153.7				284.1				474.1				—				465.0				(1,223.2		)		153.7
Income from Discontinued Operations-net of taxes	0.2				0.2				—				—				—				(0.2		)		0.2
Net Income	153.9				284.3				474.1				—				465.0				(1,223.4		)		153.9
Less: Net income attributable to noncontrolling interest	37.1				37.1				—				—				—				(37.1		)		37.1
Net Income Attributable to CPG	$	116.8			$	247.2			$	474.1			$	—			$	465.0			$	(1,186.3	)		$	116.8

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (continued)

Year Ended December 31, 2015  (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Operating Revenues
Transportation revenues	$	—			$	—			$	—			$	—			$	1,054.4			$	—			$	1,054.4
Transportation revenues-affiliated	—				—				—				—				47.5				—				47.5
Storage revenues	—				—				—				—				171.4				—				171.4
Storage revenues-affiliated	—				—				—				—				26.2				—				26.2
Other revenues	—				—				—				—				35.4				—				35.4
Total Operating Revenues	—				—				—				—				1,334.9				—				1,334.9
Operating Expenses
Operation and maintenance	20.5				(1.2		)		—				—				632.8				—				652.1
Operation and maintenance-affiliated	2.2				0.4				—				—				52.5				(2.2		)		52.9
Depreciation and amortization	—				—				—				—				139.9				—				139.9
Gain on sale of assets	—				—				—				—				(55.3		)		—				(55.3		)
Impairment of long-lived assets	—				1.8				—				—				0.6				—				2.4
Property and other taxes	—				—				—				—				75.3				—				75.3
Total Operating Expenses	22.7				1.0				—				—				845.8				(2.2		)		867.3
Equity Earnings in Unconsolidated Affiliates	—				—				—				—				60.5				—				60.5
Equity Earnings in Consolidated Affiliates	341.2				529.4				529.6				—				—				(1,400.2		)		—
Operating Income	318.5				528.4				529.6				—				549.6				(1,398.0		)		528.1
Other Income (Deductions)
Interest expense	(73.0		)		—				—				—				(1.5		)		6.9				(67.6		)
Interest expense-affiliated	(2.5		)		(40.8		)		—				—				(26.8		)		40.8				(29.3		)
Other, net	45.4				0.5				3.5				—				27.6				(47.7		)		29.3
Total Other Deductions, net	(30.1		)		(40.3		)		3.5				—				(0.7		)		—				(67.6		)
Income from Continuing Operations before Income Taxes	288.4				488.1				533.1				—				548.9				(1,398.0		)		460.5
Income Taxes	(19.1		)		146.6				—				—				25.5				—				153.0
Income from Continuing Operations	307.5				341.5				533.1				—				523.4				(1,398.0		)		307.5
Loss from Discontinued Operations-net of taxes	(0.4		)		(0.4		)		—				—				—				0.4				(0.4		)
Net Income	307.1				341.1				533.1				—				523.4				(1,397.6		)		307.1
Less: Net income attributable to noncontrolling interest	39.9				39.9				—				—				—				(39.9		)		39.9
Net Income Attributable to CPG	$	267.2			$	301.2			$	533.1			$	—			$	523.4			$	(1,357.7	)		$	267.2

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (continued)

Year Ended December 31, 2014  (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Operating Revenues
Transportation revenues	$	—			$	—			$	—			$	—			$	990.8			$	—			$	990.8
Transportation revenues-affiliated	—				—				—				—				95.7				—				95.7
Storage revenues	—				—				—				—				144.0				—				144.0
Storage revenues-affiliated	—				—				—				—				53.2				—				53.2
Other revenues	—				—				—				—				64.3				—				64.3
Total Operating Revenues	—				—				—				—				1,348.0				—				1,348.0
Operating Expenses
Operation and maintenance	—				(2.6		)		—				—				631.0				—				628.4
Operation and maintenance-affiliated	—				0.5				—				—				122.7				—				123.2
Depreciation and amortization	—				—				—				—				118.8				—				118.8
Gain on sale of assets	—				—				—				—				(34.5		)		—				(34.5		)
Property and other taxes	—				—				—				—				67.1				—				67.1
Total Operating Expenses	—				(2.1		)		—				—				905.1				—				903.0
Equity Earnings in Unconsolidated Affiliates	—				—				—				—				46.6				—				46.6
Equity Earnings in Consolidated Affiliates	268.7				269.6				—				—				—				(538.3		)		—
Operating Income	268.7				271.7				—				—				489.5				(538.3		)		491.6
Other Income (Deductions)
Interest expense-affiliated	—				—				—				—				(62.0		)		—				(62.0		)
Other, net	—				(0.1		)		—				—				8.9				—				8.8
Total Other Deductions, net	—				(0.1		)		—				—				(53.1		)		—				(53.2		)
Income from Continuing Operations before Income Taxes	268.7				271.6				—				—				436.4				(538.3		)		438.4
Income Taxes	—				2.9				—				—				166.8				—				169.7
Income from Continuing Operations	268.7				268.7				—				—				269.6				(538.3		)		268.7
Loss from Discontinued Operations-net of taxes	(0.6		)		(0.6		)		—				—				—				0.6				(0.6		)
Net Income	$	268.1			$	268.1			$	—			$	—			$	269.6			$	(537.7	)		$	268.1

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2016  (in millions, net of taxes)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Income	$	153.9			$	284.3			$	474.1			$	—			$	465.0			$	(1,223.4	)		$	153.9
Other comprehensive income
Net unrealized gain (loss) on cash flow hedges	1.3				(0.8		)		—				—				2.1				(1.3		)		1.3
Unrecognized pension and OPEB benefit	2.0				1.7				—				—				0.3				(2.0		)		2.0
Total other comprehensive income	3.3				0.9				—				—				2.4				(3.3		)		3.3
Total Comprehensive Income	157.2				285.2				474.1				—				467.4				(1,226.7		)		157.2
Less: Comprehensive Income-noncontrolling interest	37.3				37.3				—				—				—				(37.3		)		37.3
Comprehensive Income-controlling interests	$	119.9			$	247.9			$	474.1			$	—			$	467.4			$	(1,189.4	)		$	119.9

Year Ended December 31, 2015  (in millions, net of taxes)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Income	$	307.1			$	341.1			$	533.1			$	—			$	523.4			$	(1,397.6	)		$	307.1
Other comprehensive income
Net unrealized gain (loss) on cash flow hedges	0.2				(1.6		)		—				—				1.8				(0.2		)		0.2
Unrecognized pension and OPEB benefit	5.2				5.4				—				—				(0.2		)		(5.2		)		5.2
Total other comprehensive income	5.4				3.8				—				—				1.6				(5.4		)		5.4
Total Comprehensive Income	312.5				344.9				533.1				—				525.0				(1,403.0		)		312.5
Less: Comprehensive Income-noncontrolling interest	40.0				40.0				—				—				—				(40.0		)		40.0
Comprehensive Income-controlling interests	$	272.5			$	304.9			$	533.1			$	—			$	525.0			$	(1,363.0	)		$	272.5

Year Ended December 31, 2014  (in millions, net of taxes)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Income	$	268.1			$	268.1			$	—			$	—			$	269.6			$	(537.7	)		$	268.1
Other comprehensive income
Net unrealized gain (loss) on cash flow hedges	1.0				—				—				—				1.0				(1.0		)		1.0
Unrecognized pension and OPEB cost	(9.7		)		(9.7		)		—				—				—				9.7				(9.7		)
Total other comprehensive income	(8.7		)		(9.7		)		—				—				1.0				8.7				(8.7		)
Total Comprehensive Income	$	259.4			$	258.4			$	—			$	—			$	270.6			$	(529.0	)		$	259.4

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

Year Ended December 31, 2016 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Cash Flows from Operating Activities	$	(213.6	)		$	473.7			$	(3.0	)		$	—			$	712.0			$	(608.9	)		$	360.2
Investing Activities
Capital expenditures	—				—				—				—				(1,438.1		)		—				(1,438.1		)
Insurance recoveries	—				—				—				—				3.0				—				3.0
Change in short-term lendings-affiliated	(736.1		)		(490.4		)		3.3				—				(37.9		)		1,261.1				—
Proceeds from disposition of assets	—				—				—				—				10.4				—				10.4
Contributions to equity investees	—				—				—				—				(6.2		)		—				(6.2		)
Distributions from equity investees	—				—				—				—				2.2				—				2.2
Other investing activities	10.3				—				—				—				(9.7		)		—				0.6
Net Cash Flows (used for) provided by Investing Activities	(725.8		)		(490.4		)		3.3				—				(1,476.3		)		1,261.1				(1,428.1		)
Financing Activities
Change in short-term borrowings	—				—				—				—				(15.0		)		—				(15.0		)
Change in short-term borrowings-affiliated	401.0				—				570.8				—				789.3				(1,261.1		)		500.0
Payment of short-term borrowings-affiliated	(500.0		)		—				—				—				—				—				(500.0		)
Payment of capital lease obligations and other debt related costs	(1.1		)		—				—				—				(4.3		)		—				(5.4		)
Issuance of common stock to TransCanada	500.1				—				—				—				—				—				500.1
Quarterly distributions to unitholders	—				—				—				—				(76.9		)		76.9				—
Distribution to noncontrolling interest in Columbia OpCo	—				—				(573.0		)		—				—				573.0				—
Distribution to noncontrolling interest	—				—				—				—				—				(41.0		)		(41.0		)
Acquisition of treasury stock	(6.2		)		—				—				—				—				—				(6.2		)
Dividends paid - common stock	(105.1		)		—				—				—				—				—				(105.1		)
Dividends paid - TransCanada	(110.5		)		—				—				—				—				—				(110.5		)
Net Cash Flows from (used for) Financing Activities	178.2				—				(2.2		)		—				693.1				(652.2		)		216.9
Change in cash and cash equivalents	(761.2		)		(16.7		)		(1.9		)		—				(71.2		)		—				(851.0		)
Cash and cash equivalents at beginning of period	800.0				46.7				1.9				—				82.3				—				930.9
Cash and Cash Equivalents at End of Period	$	38.8			$	30.0			$	—			$	—			$	11.1			$	—			$	79.9

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (continued)

Year Ended December 31, 2015 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Cash Flows from Operating Activities	$	(29.7	)		$	(49.6	)		$	3.5			$	—			$	589.5			$	(20.2	)		$	493.5
Investing Activities
Capital expenditures	—				(32.7		)		—				—				(1,181.0		)		32.7				(1,181.0		)
Insurance recoveries	—				—				—				—				2.1				—				2.1
Change in short-term lendings-affiliated	—				(83.9		)		(3.3		)		—				(0.6		)		233.3				145.5
Proceeds from disposition of assets	—				26.2				—				—				84.1				(32.7		)		77.6
Contributions to equity investees	—				(1,217.3		)		(446.2		)		—				(1.4		)		1,663.5				(1.4		)
Distributions from equity investees	—				—				—				—				16.0				—				16.0
Other investing activities	(5.2		)		—				—				—				(22.2		)		—				(27.4		)
Net Cash Flows used for Investing Activities	(5.2		)		(1,307.7		)		(449.5		)		—				(1,103.0		)		1,896.8				(968.6		)
Financing Activities
Change in short-term borrowings	—				—				—				—				15.0				—				15.0
Change in short-term borrowings-affiliated	99.0				(5.1		)		—				—				(113.1		)		(233.3		)		(252.5		)
Issuance of long-term debt	2,745.9				—				—				—				—				—				2,745.9
Debt related costs	(27.9		)		6.3				—				—				(2.0		)		—				(23.6		)
Issuance of long-term debt-affiliated	—				1,217.3				—				—				—				—				1,217.3
Payments of long-term debt-affiliated, including current portion	(1,848.2		)		—				—				—				(959.6		)		—				(2,807.8		)
Proceeds from the issuance of common units, net of offering costs	—				—				1,170.0				—				(1.6		)		—				1,168.4
Issuance of common stock, net of offering costs	1,394.7				—				—				—				—				—				1,394.7
Contribution of capital from parent	—				—				—				—				1,663.5				(1,663.5		)		—
Distribution of IPO proceeds to NiSource	—				—				(500.0		)		—				—				—				(500.0		)
Distribution to NiSource	(1,450.0		)		—				—				—				—				—				(1,450.0		)
Quarterly distributions to unitholders	—				—				—				—				(43.4		)		43.4				—
Distribution to noncontrolling interest in Columbia OpCo	—				—				(187.3		)		—				—				187.3				—
Distribution received from Columbia OpCo	—				187.3				—				—				—				(187.3		)		—
Distribution to noncontrolling interest	—				—				—				—				—				(23.2		)		(23.2		)
Dividends paid - common stock	(79.5		)		—				—				—				—				—				(79.5		)
Transfer from NiSource	0.9				(1.8		)		(34.8		)		—				36.5				—				0.8
Net Cash Flows from Financing Activities	834.9				1,404.0				447.9				—				595.3				(1,876.6		)		1,405.5
Change in cash and cash equivalents	800.0				46.7				1.9				—				81.8				—				930.4
Cash and cash equivalents at beginning of period	—				—				—				—				0.5				—				0.5
Cash and Cash Equivalents at End of Period	$	800.0			$	46.7			$	1.9			$	—			$	82.3			$	—			$	930.9

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Notes to Consolidated and Combined Financial Statements

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (continued)

Year Ended December 31, 2014 (in millions)	CPG				CEG				Columbia OpCo				OpCo GP				Non-guarantor Subsidiaries				Consolidating adjustments and eliminations				CPG Consolidated
Net Cash Flows from Operating Activities	$	—			$	(3.7	)		$	—			$	—			$	570.7			$	(2.2	)		$	564.8
Investing Activities
Capital expenditures	—				—				—				—				(747.2		)		—				(747.2		)
Insurance recoveries	—				—				—				—				11.3				—				11.3
Change in short-term lendings-affiliated	—				4.8				—				—				(62.0		)		—				(57.2		)
Proceeds from disposition of assets	—				—				—				—				9.3				—				9.3
Contributions to equity investees	—				—				—				—				(69.2		)		—				(69.2		)
Other investing activities	—				—				—				—				(7.1		)		—				(7.1		)
Net Cash Flows used for Investing Activities	—				4.8				—				—				(864.9		)		—				(860.1		)
Financing Activities
Change in short-term borrowings-affiliated	—				5.2				—				—				(472.3		)		—				(467.1		)
Debt related costs	—				(6.3		)		—				—				(0.1		)		—				(6.4		)
Issuance of long-term debt-affiliated	—				—				—				—				768.9				—				768.9
Distribution to parent	—				—				—				—				(2.2		)		2.2				—
Net Cash Flows from Financing Activities	—				(1.1		)		—				—				294.3				2.2				295.4
Change in cash and cash equivalents	—				—				—				—				0.1				—				0.1
Cash and cash equivalents at beginning of period	—				—				—				—				0.4				—				0.4
Cash and Cash Equivalents at End of Period	$	—			$	—			$	—			$	—			$	0.5			$	—			$	0.5

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

CPG's principal 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)). CPG'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 CPG's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, CPG's principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

CPG management, including CPG’s principal executive officer and principal financial officer, are responsible for establishing and maintaining CPG’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. CPG’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 2016, CPG conducted an evaluation of its internal control over financial reporting. Based on this evaluation, CPG management concluded that CPG’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 CPG in the reports that it files or submits under the Exchange Act is accumulated and communicated to CPG’s management, including its principal executive officer and its principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There have been no changes in CPG’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, CPG’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.

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

The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

We have engaged Deloitte & Touche LLP ("Deloitte") 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, 2016 and 2015.

(in millions)		2016			2015
Audit Fees (1)(2)		$	3.4		$	2.9
Audit-Related Fees (3)		0.9			0.1
Tax Fees (4)		0.1			—
All Other Fees (5)		—			—
Total		$	4.4		$	3.0

⁽¹⁾ These are fees for professional services performed by Deloitte for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Form 10-Q filings, and services that are normally provided in connection with statutory and regulatory filings or engagements.

⁽²⁾ These are fees for the assurance and related services performed by Deloitte that are reasonably related to the performance of the audit or review of the Company’s financial statements. In 2016, these fees include services provided by Deloitte in connection with the Merger. In 2015, these fees include services provided by Deloitte in connection with Columbia Pipeline Partners LP’s initial public offering of its outstanding limited partnership interests.

⁽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

During fiscal year 2016 until the closing of the Merger on July 1, 2016, the Audit and Risk Committee approved all audit, audit related and non-audit services provided to the Company by Deloitte prior to management engaging the auditor for those purposes. The Audit and Risk Committee’s practice was to consider for pre-approval annually all audit, audit related and non-audit services proposed to be provided by our independent auditors for the fiscal year. Upon the closing of the Merger, the CPG board of directors has taken on the role of the Audit and Risk Committee. Additional fees for other proposed audit-related or non-audit services (not within the scope of the approved audit engagement) may be considered and, if appropriate, approved by the board of directors. In no event, however, will any non-audit related service be approved by the board of directors that would result in the independent auditor no longer being considered independent under the applicable SEC rules. In making its recommendation to appoint Deloitte as our independent auditor, the board of directors has considered whether the provision of the non-audit services rendered by Deloitte is compatible with maintaining that firm’s independence.

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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."

Index	Page
Report of Independent Registered Public Accounting Firm	38
Consolidated Balance Sheets	39
Statements of Consolidated and Combined Operations	41
Statements of Consolidated and Combined Comprehensive Income	42
Statements of Consolidated and Combined Cash Flows	43
Statements of Consolidated and Combined Equity	44
Notes to Consolidated and Combined Financial Statements	46

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 CPG, 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 CPG’s subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of CPG and its subsidiaries on a consolidated basis. CPG agrees to furnish a copy of any such instrument to the SEC upon request.

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SIGNATURES

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

 

			Columbia Pipeline Group, Inc.
			(Registrant)
Date:	February 17, 2017	By:	/s/ STANLEY G. CHAPMAN, III
			Stanley G. Chapman, III
			President

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/	STANLEY G. CHAPMAN, III		Director and President	Date: February 17, 2017
			Stanley G. Chapman, III		(Principal Executive Officer)
		/s/	NATHANIEL A. BROWN		Controller and Principal Financial Officer	Date: February 17, 2017
			Nathaniel A. Brown		(Principal Financial Officer and Principal Accounting Officer)
		/s/	RONALD L. COOK		Director	Date: February 17, 2017
			Ronald L. Cook
		/s/	BRANDON M. ANDERSON		Director	Date: February 17, 2017
			Brandon M. Anderson

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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 Group, Inc.

(2.1)	Separation and Distribution Agreement, dated as of June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 2.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
(2.2)	Agreement and Plan of Merger, dated as of March 17, 2016, by and among TransCanada PipeLines Limited, TransCanada PipeLine USA Ltd., Taurus Merger Sub Inc., Columbia Pipeline Group, Inc., and solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII thereof, TransCanada Corporation (Incorporated by reference to Exhibit 2.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on March 18, 2016).
(2.3)	Agreement and Plan of Merger dated as of November 1, 2016, by and among Columbia Pipeline Group, Inc., Columbia Pipeline Partners L.P., MLP GP and Pony Merger Sub LLC (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K, File No. 001-36838, filed on November 2, 2016).
(3.1)	Second Restated Certificate of Incorporation of Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 3.1 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on August 2, 2016).
(3.2)	Bylaws of Targus Merger Sub Inc. (Incorporated by reference to Exhibit 3.2 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on August 2, 2016).
(4.1)	Indenture, dated as of May 22, 2015, by and among Columbia Pipeline Group, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(4.2)	Registration Rights Agreement, dated as of May 22, 2015, by and among Columbia Pipeline Group, Inc., the Guarantors named therein and the Initial Purchasers (Incorporated by reference to Exhibit 4.2 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(4.3)	Form of 2.45% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(4.4)	Form of 3.30% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(4.5)	Form of 4.50% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(4.6)	Form of 5.80% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.1)	Revolving Credit Agreement, dated as of December 5, 2014, by and among Columbia Pipeline Group, Inc., as Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent, Barclays Bank PLC, The Bank of Nova Scotia and BNP Paribas, as Co-Documentation Agents and Barclays Bank PLC, Citigroup Global Markets, Inc., The Bank of Nova Scotia, BNP Paribas and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 10.6 to the Columbia Pipeline Group, Inc. Form 10 (File No. 001-36838) filed on February 6, 2015).
(10.2)	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, Wells Fargo Bank, National Association, as Administrative Agent and The Bank of Tokyo-Mitsubishi UFJ, LTD, as Syndication Agent (Incorporated by reference to Exhibit 10.7 to the Columbia Pipeline Group, Inc. Form 10 (File No. 001-36838) filed on February 6, 2015).
(10.3)	Trademark License Agreement, dated as of February 11, 2015, between NiSource Corporate Services Company and Columbia Pipeline Group Services Company filed April 17, 2015. (Incorporated by reference to Exhibit 10.3 to the Columbia Pipeline Group, Inc. Amendment No. 2 Form 10 (File No. 001-36838) filed on April 17, 2015).

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(10.4)†	Employment Offer Letter Agreement, dated May 14, 2008, between NiSource Inc. and Stephen P. Smith, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.21 to the Columbia Pipeline Group, Inc. Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.5)†	Retention Bonus Letter Agreement, dated March 11, 2014, between NiSource Inc. and Shawn Patterson, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.22 to the Columbia Pipeline Group, Inc. Form 10 Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.6)†	Retention Bonus Letter Agreement, dated September 2, 2014, between NiSource Inc. and Stanley Chapman, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.23 to the Columbia Pipeline Group, Inc. Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.7)	Tax Allocation Agreement, dated June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
(10.8)	Employee Matters Agreement, dated June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc., (Incorporated by reference to Exhibit 10.2 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
(10.9)	Form of Transition Services Agreement (NiSource to CPG) between NiSource Corporate Services Company and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.4 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.10)	Form of Transition Services Agreement (CPG to NiSource) between NiSource Corporate Services Company and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.5 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.11)†	Form of Columbia Pipeline Group, Inc. 2015 Omnibus Plan (Incorporated by reference to Exhibit 10.8 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.12)†	Form of Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.9 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.13)†	Form of Performance Share Award Agreement (Incorporated by reference to Exhibit 10.10 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.14)†	Form of Restricted Stock Unit Award Agreement with Nonemployee Directors (Incorporated by reference to Exhibit 10.11 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.15)†	Form of Restricted Stock Unit Award Agreement with Nonemployee Directors of Columbia Pipeline Group, Inc. Relating to Vested by Unpaid NiSource Restricted Stock Units (Incorporated by reference to Exhibit 10.12 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.16)†	Form of Director Restricted Stock Unit Award Agreement Relating to Unvested NiSource Restricted Stock Units (Incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.17)†	Form of Columbia Pipeline Group, Inc. Phantom Stock Unit Agreement (Incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.18)†	Form of Change in Control and Termination Agreement with Robert Skaggs (Incorporated in reference to Exhibit 10.15 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.19)†	Form of Change in Control and Termination Agreement with Other Named Executive Officers (Incorporated in reference to Exhibit 10.16 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).

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(10.20)†	Form of Columbia Pipeline Group, Inc. Executive Severance Policy (Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.21)†	Form of Columbia Pipeline Group Executive Deferred Compensation Plan (Incorporated by reference to Exhibit 10.18 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.22)†	Form of Columbia Pipeline Group Savings Restoration Plan (Incorporated by reference to Exhibit 10.19 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.23)†	Form of Columbia Pipeline Group Pension Restoration Plan (Incorporated by reference to Exhibit 10.20 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
(10.24)	Form of Commercial Paper Dealer Agreement (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on October 6, 2015)
(10.25)	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 10.2 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on November 3, 2015).
(10.26)	Credit Agreement, dated as of December 16, 2016, by and among Columbia Pipeline Group, Inc., as borrower, TransCanada PipeLines Limited, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on January 30, 2017).
(12.1)*	Ratio of Earnings to Fixed Charges
(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

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