Exhibit 99.1

FORM 51-102F4
BUSINESS ACQUISITION REPORT

ITEM 1 IDENTITY OF COMPANY

1.1Name and Address of Company

TransCanada Corporation (“TransCanada” or the “Corporation”)
450 1 Street SW
Calgary, Alberta T2P 5H1

1.2Executive Officer

For further information please contact Christine R. Johnston, Vice-President, Law and Corporate Secretary at 403-920-2000.

ITEM 2 DETAILS OF ACQUISITION

2.1Nature of Business Acquired

Columbia Pipeline Group Inc. (“Columbia”) is a growth-oriented Delaware corporation which was formed by NiSource Inc. on September 26, 2014 to own, operate and develop a portfolio of pipeline, storage and related midstream assets. Columbia owns approximately 15,000 miles (24,140 km) of strategically located interstate natural gas pipelines extending from New York to the Gulf of Mexico and one of the U.S.’s largest underground natural gas storage systems, with approximately 296 Billion cubic feet (“Bcf”) of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2015, 94.6% of Columbia’s revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, was generated under firm revenue contracts. As of December 31, 2015, these contracts had a weighted average remaining contract life of 4.8 years.

Columbia owns these assets through CPG OpCo LP (‘‘Columbia OpCo’’), a partnership between Columbia’s wholly owned subsidiary Columbia Energy Group (‘‘CEG’’) and Columbia Pipeline Partners LP (‘‘Columbia MLP’’). Columbia MLP is a fee-based, growth-oriented Delaware limited partnership formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets.  Through its wholly owned subsidiary CEG, Columbia owns the general partner of Columbia MLP, all of Columbia MLP’s incentive distribution rights and all of Columbia MLP’s subordinated units, which, in the aggregate, represent a 46.5% limited partner interest in Columbia MLP. Columbia MLP completed its initial public offering on February 11, 2015, selling 53.5% of its limited partner interests. Columbia MLP units trade under the ticker symbol “CPPL” on the New York Stock Exchange.

Columbia’s significant assets include the following:

·Columbia Gas Transmission. Columbia Gas Transmission’s pipeline system consists of 11,272 miles (18,141 km) of natural gas transmission pipeline. It has transportation capacity of approximately 10 Bcf/day, transports an average of approximately 3.9 Bcf/day and serves communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission owns and leases approximately 819,500 acres (331,639 hectares) of underground storage, 3,432 storage wells,

which includes 35 storage fields in four states with approximately 620 Bcf in total operational capacity, with approximately 286 Bcf of working gas capacity.

·Millennium Pipeline. Columbia also owns a 47.5% ownership interest in Millennium Pipeline, which transports an average of 1.1 Bcf/day 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. The Millennium Pipeline system consists of approximately 253 miles (407 km) of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity.

·Columbia Gulf. The Columbia Gulf pipeline system consists of 3,341 miles (5,377 km) of natural gas transmission pipeline and transports an average of approximately 1.5 Bcf/day, located primarily in Louisiana, Mississippi, Tennessee and Kentucky.

·Columbia Midstream Group, LLC (‘‘Columbia Midstream’’). Columbia Midstream provides natural gas producer services including gathering, treating, conditioning, processing, compression and liquids handling in the Marcellus/Utica.

Columbia is advancing US$7.3 billion of commercially secured projects and modernization investments.

Schedule A attached hereto discusses certain risks related to the Acquisition (as defined below) and certain risks related to Columbia.

2.2Acquisition Date

July 1, 2016 (the “Acquisition Closing Date”).

2.3Consideration

On July 1, 2016, TransCanada PipeLines Limited (“TCPL”), a wholly-owned subsidiary of the Corporation, completed the indirect acquisition (the “Acquisition”) of all of the outstanding shares of Columbia valued at US$13 billion, comprised of a purchase price of approximately US$10.3 billion (the “Purchase Price”) and Columbia debt of approximately US $2.7 billion. TransCanada was a party to the Acquisition for the limited purposes of providing representations and warranties, pursuing regulatory approvals and obtaining the financing for the Acquisition (collectively, the “Limited Purposes”).

The Purchase Price was funded as follows:

A.Subscription Receipt Offering

On March 17, 2016, the Corporation entered into an agreement with a syndicate of underwriters (the “Underwriters”), under which they agreed to purchase from TransCanada and sell to the public 92 million subscription receipts (“Subscription Receipts”) at a price of $45.75 per Subscription Receipt.  At the closing of the offering on April 1, 2016 (the “Offering Closing Date”), the Underwriters exercised in full their over-allotment option, such that a total of 96.6 million Subscription Receipts were issued for total gross proceeds of $4.4 billion.

The Subscription Receipts were automatically exchanged for TransCanada common shares on a one for one basis following the closing of the Acquisition. On July 4, 2016, being the first trading date in Canada following the Acquisition Closing Date, trading commenced in the 96.6 million common shares and the Subscription Receipts were delisted, in accordance with the terms of the subscription receipt agreement.

B.Acquisition Credit Facilities

An aggregate principal amount of U.S. $6.9 billion was drawn by TCPL and TransCanada PipeLine USA Ltd. under bridge credit facilities underwritten by various financial institutions (the “Acquisition Credit Facilities”).

C.Existing Cash on Hand

The remainder of the Purchase Price was financed by the Corporation through existing cash on hand.

2.4Effect on Financial Position

Except as described below, TransCanada does not have any current plans for material changes in its business affairs or the affairs of Columbia that would reasonably be expected to have a significant effect on the financial performance and financial position of TransCanada.

In connection with the Acquisition, TransCanada is targeting annual cost, revenue and financing benefits of approximately U.S. $250 million.

Portfolio management will play an important role in the permanent financing of the Acquisition through the planned monetization of TransCanada’s U.S. Northeast merchant power assets and a minority interest in its Mexico natural gas pipeline business. The process of engaging advisors has been completed and the initial stages of soliciting interested parties is underway. TransCanada expects to provide an update by the end of 2016, and proceeds from these monetizations will be used to retire draws under Acquisition Credit Facilities

In addition, TransCanada has retained a financial advisor to assist in a review of strategic alternatives for its master limited partnership (“MLP”) holdings. TransCanada expects to be in a position to communicate its determination regarding the future of TC PipeLines, LP and Columbia MLP later in 2016. The Corporation does not anticipate any asset dropdowns to the MLPs until the review has been completed.

2.5Prior Valuations

To the knowledge of the Corporation, there has not been any valuation opinion obtained within the last twelve months by Columbia or TransCanada required by securities legislation or a Canadian exchange or market to support the consideration paid by the Corporation of any of its subsidiaries in connection with the Acquisition.

2.6Parties to Transaction

The TransCanada parties to the Acquisition included TCPL, TransCanada PipeLine USA Ltd. and Taurus Merger Sub Inc., all direct or indirect wholly-owned subsidiaries of the Corporation, and TransCanada was a party to the Acquisition for the Limited Purposes.

None of the Columbia parties to the Acquisition are informed persons, associates or affiliates of TransCanada (as such terms are defined in National Instrument 51-102 — Continuous Disclosure Obligations).

2.7Date of Report

July 22, 2016

ITEM 3 FINANCIAL STATEMENTS AND OTHER INFORMATION

The following financial statements are included as schedules to this Business Acquisition Report:

Schedule B

Audited consolidated balance sheets of Columbia as of December 31, 2015 and 2014, and 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, 2015, and the notes thereto.

Schedule C

Unaudited condensed consolidated financial statements of Columbia as at and for the three months ended March 31, 2016 and 2015.

Schedule D

Unaudited pro forma condensed consolidated financial statements of TransCanada as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, including the pro forma earnings per share.

Caution Regarding Unaudited Pro Forma Condensed Consolidated Financial Statements

This Business Acquisition Report contains the unaudited pro forma condensed consolidated financial statements of the Corporation comprised of the condensed consolidated balance sheet of the Corporation as at March 31, 2016 and the condensed and consolidated statements of income of the Corporation for the year ended December 31, 2015 and for the three months ended March 31, 2016, giving effect to: (i) the Acquisition; and (ii) assumptions related to the financing of the Acquisition, including drawings under the Acquisition Credit Facilities and receipt of proceeds from the issuance of common shares of the Corporation upon the exchange of the Subscription Receipts. Such unaudited pro forma condensed consolidated financial statements have been prepared using certain of the Corporation’s and Columbia’s respective historical financial statements as more particularly described in the notes to such unaudited pro forma condensed consolidated financial statements. In preparing such unaudited pro forma condensed consolidated financial statements, the Corporation has not independently verified the financial statements of Columbia that were used to prepare the unaudited pro forma condensed consolidated financial statements. Such unaudited pro forma condensed consolidated financial statements are not intended to be indicative of the results that would actually have occurred, or the results expected in future periods, had the events reflected therein occurred on the dates indicated. Actual amounts recorded upon the finalization of the purchase price allocation under the Acquisition may differ from the amounts reflected in such unaudited pro forma condensed consolidated financial statements. Since the unaudited pro forma condensed consolidated financial statements have been developed to retroactively show the effect of a transaction that occurred at a later date (even though this was accomplished by following generally accepted practice using reasonable assumptions), there are limitations inherent in the very nature of pro forma data. The data contained in the unaudited pro forma condensed consolidated financial statements represents only a simulation of the potential financial impact of the Corporation’s acquisition of Columbia. The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effect directly attributable to the Acquisition. These pro forma adjustments are tentative and are based on currently available financial information and certain estimates and assumptions. The actual adjustments to the consolidated financial statements will depend on a number of factors. Therefore, it is expected that the actual adjustments will differ from the pro forma adjustments, and the differences may be material. Undue reliance should not be placed on such unaudited pro forma condensed consolidated financial statements.

Special Note Regarding Forward-Looking Statements

This Business Acquisition Report includes certain forward looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall. Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this Business Acquisition Report. Such forward-looking

information is based on the following key assumptions: planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business, inflation rates, commodity prices and capacity prices, timing of financings and hedging, regulatory decisions and outcomes, foreign exchange rates, interest rates, tax rates, planned and unplanned outages and the use of our pipeline and energy assets, integrity and reliability of our assets, access to capital markets, anticipated construction costs, schedules and completion dates, acquisitions and divestitures.

Such forward looking information is subject to risks and uncertainties, including but not limited to: our ability to successfully implement our strategic initiatives and whether they will yield the expected benefits including the expected benefits of the acquisition of Columbia, timing and execution of our planned asset sales, the operating performance of our pipeline and energy assets, economic and competitive conditions in North America and globally, the availability and price of energy commodities and changes in market commodity prices, the amount of capacity sold and rates achieved in our pipeline businesses, the amount of capacity payments and revenues we receive from our energy business, regulatory decisions and outcomes, outcomes of legal proceedings, including arbitration and insurance claims, performance of our counterparties, changes in the political environment, changes in environmental and other laws and regulations, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and foreign exchange rates, weather, cyber security and technological developments. You can read more about these risks and others in our Quarterly Report to shareholders dated April 28, 2016 and our 2015 Annual Report filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC) and available at www.transcanada.com.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

Dated this 22nd day of July, 2016
	/s/ Christine R. Johnston
	Christine R. Johnston Vice-President, Law and Corporate Secretary TransCanada Corporation

SCHEDULE A

Risks Related to the Acquisition

Information provided by Columbia

All information relating to Columbia included herein is based on public filings by Columbia. Although the Corporation has conducted what it believes to be a prudent and thorough level of investigation in connection with the Acquisition, an unavoidable level of risk remains regarding the accuracy and completeness of such information.

Historical Financial Information and Pro Forma Financial Information

The historical financial information relating to Columbia included herein, including such information used to prepare the pro forma financial information, has been derived on a historical basis from the historical accounting records of Columbia. The historical financial information may not reflect what Columbia’s financial position, results of operations or cash flows would have been had the Corporation owned all of the outstanding shares of capital stock of Columbia during the period presented or what the Corporation’s financial position, results of operations or cash flows will be in the future. The historical financial information does not contain any adjustments to reflect changes that may occur in the Corporation’s cost structure, financing and operations as a result of the Acquisition.

In preparing the pro forma financial information included herein, the Corporation has given effect to, among other items, the financing and completion of the Acquisition. The assumptions and estimates underlying the pro forma financial information may be materially different from the Corporation’s actual experience going forward. See “Caution Regarding Unaudited Pro Forma Condensed Consolidated Financial Statements” and “ Special Note Regarding Forward-Looking Information”.

Unexpected Costs or Liabilities Related to the Acquisition

Although the Corporation conducted what it believed to be a prudent and thorough level of investigation in connection with the Acquisition, an unavoidable level of risk remains regarding any undisclosed or unknown liabilities of, or issues concerning, Columbia. Following the Acquisition, the Corporation may discover that it has acquired substantial undisclosed liabilities. In addition, the Corporation may be unable to retain existing Columbia customers or employees following the Acquisition. Following the closing of the Acquisition, the Corporation will have no right to claim indemnification under the merger agreement through which the Acquisition was effected. The existence of undisclosed liabilities, the Corporation’s inability to retain existing Columbia customers or employees and the inability to claim indemnification could, however, have an adverse impact on the Corporation’s business, financial condition, results of operations and cash flows.

Historic and current performance of Columbia’s business and operations may not be indicative of success in future periods. The future performance of Columbia may be influenced by, among other factors, economic downturns, increased environmental regulation, turmoil in financial markets, unfavourable regulatory decisions, rising interest rates and other factors beyond the Corporation’s control. As a result of any one or more of these factors, among others, the operations and financial performance of Columbia may be negatively affected during such period which may adversely affect the future financial results of the Corporation.

Integration of Columbia

The ability to realize the anticipated benefits of the Acquisition will depend in part on the Corporation successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as on the ability of the Corporation to realize the anticipated growth and potential synergies from integrating Columbia’s business into the Corporation’s current operations following the Acquisition. To effectively integrate Columbia into its current operations, the Corporation must establish appropriate operational, administrative, finance, management systems and controls and marketing functions relating to Columbia. This will require substantial attention from the Corporation’s management team. This diversion of management attention, as well as any other difficulties which the Corporation may encounter in completing the transition and integration process, could have an adverse impact on the Corporation’s business, financial condition, results of operations and cash flows. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the ability of the Corporation to achieve all or some of the

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anticipated benefits of the Acquisition. There can be no assurance that the Corporation will be successful in integrating Columbia’s operations, or that the expected benefits will be realized.

Foreign Currency Exposure

After giving effect to the Acquisition, a significantly increased portion of the Corporation’s earnings and net assets are denominated in U.S. dollars. Accordingly, fluctuations in exchange rates between the Canadian and U.S. dollar may have an increased adverse effect on the Corporation’s results and financial condition. Future events that may significantly increase or decrease the risk of future movement in the exchange rates for these currencies cannot be predicted.

Failure to Realize the Anticipated Benefits of the Acquisition

The Corporation believes that the Acquisition will provide certain benefits to TransCanada. There is, however, a risk that some or all of the expected benefits of the Acquisition may fail to materialize, or may not occur within the time periods anticipated by the Corporation. The realization of such benefits may be affected by a number of factors, many of which are beyond the control of the Corporation. If the Acquisition fails to provide the results that the Corporation anticipates, the Acquisition could materially and adversely affect the Corporation and its financial results.

Increased Indebtedness

The Acquisition Credit Facilities represent a significant increase in the Corporation’s consolidated indebtedness. Such additional indebtedness will increase the Corporation’s interest expense and debt service obligations and may have a negative effect on the Corporation’s results of operations. In addition, all of Columbia’s existing indebtedness are included in the Corporation’s consolidated indebtedness. As of December 31, 2015, Columbia and its subsidiaries had U.S.$2.8 billion in outstanding indebtedness, comprised of U.S.$2.75 billion in aggregate principal amount of its senior notes and U.S.$15 million under Columbia MLP’s credit facility. The Corporation’s existing and future level of debt, including the addition of Columbia’s and Columbia MLP’s future level of debt, could have important consequences to the Corporation, including the following: (i) the Corporation’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; (ii) the funds that the Corporation has available for operations and payment of dividends will be reduced by that portion of the Corporation’s cash flow required to make principal and interest payments on outstanding debt; and (iii) the Corporation’s debt level could make the Corporation more vulnerable than its competitors with less debt to competitive pressures or a downturn in the Corporation’s business or the economy generally. The Corporation’s ability to service its increased debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, interest rate fluctuations and financial, business, regulatory and other factors, some of which are beyond the Corporation’s control. If the Corporation’s operating results are not sufficient to service its current or future indebtedness, the Corporation may be forced to take actions such as reducing dividends, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing its debt, or seeking additional equity capital. It is currently contemplated that a portion of the Acquisition Credit Facilities will be repaid from the proceeds of asset sales within 24 months following completion of the Acquisition. The Corporation may not be able to effect any of these actions on satisfactory terms, or at all.

The Corporation currently has an investment grade credit rating from S&P, Moody’s and DBRS. However, its credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. DBRS has initiated a rating action in connection with the Acquisition. The increased indebtedness of the Corporation arising from the Acquisition could be a factor considered by ratings agencies in downgrading the Corporation’s credit rating. If a rating agency were to downgrade the Corporation’s rating below investment grade, the Corporation’s borrowing costs would increase and its funding sources could decrease. In addition, a failure by the Corporation to maintain an investment grade credit rating could affect its business relationships with suppliers and operating partners. A credit downgrade could also adversely affect the availability and cost of capital needed to fund the growth investments that are a central element of the Corporation’s long-term business strategy.

Significant Transaction and Related Costs

The Corporation incurred a number of costs associated with completing the Acquisition and expects to incur additional costs integrating the operations of the Corporation and Columbia. The substantial majority of such costs will be non-recurring expenses resulting from the Acquisition and will consist of transaction costs related to the Acquisition, facilities and systems

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consolidation costs and employment-related costs. Additional unanticipated costs may be incurred in the integration of the Corporation and Columbia’s respective businesses.

Risks Related to Columbia

The principal business of Columbia is the operation of natural gas pipelines and natural gas storage facilities and, accordingly, the Corporation believes, based on its investigation in connection with the Acquisition and subject to the risk factor noted above under “Risks Relating to the Acquisition — Unexpected Costs or Liabilities Related to the Acquisition”, that the risk factors relating to Columbia’s business are generally the same as those disclosed by the Corporation under the headings “Natural Gas Pipelines — Business Risks” and “Other Information — Risks and Risk Management” in the Corporation’s 2015 MD&A. In addition, certain aspects of Columbia’s business and structure which are specific to Columbia may present additional risks to the combined business of the Corporation following the completion of the Acquisition. Additional risks specifically related to Columbia are described below.

Marcellus and Utica basin supply for downstream connecting pipelines

Columbia’s natural gas pipelines and transmission infrastructure assets depend largely on supply from the Marcellus and Utica basins. We will monitor any changes in Columbia’s customers’ gas production plans and how these changes may impact Columbia’s existing assets and growth projects. There is competition for this supply from several pipelines within the basin. An overall decrease in production and/or competing demand for supply could impact throughput on pipelines connected to the Marcellus and Utica basins that, in turn, could impact future overall revenues generated. The amount actually produced from the Marcellus and Utica basins depends on many variables, including the price of natural gas, basin-on-basin competition, downstream pipeline tolls, demand within the basins and the overall value of the reserves, including liquids content.

Concentration of Business with Key Customers

Columbia is subject to risks of loss resulting from non-performance or non-renewal by its customers. Columbia depends on certain key customers for a significant portion of its revenues. In addition, Columbia is making significant capital expenditures to expand its 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. Columbia’s credit support arrangements may not be adequate to fully eliminate customer credit risk. The Corporation may not be able to effectively remarket capacity related to nonperforming customers. The deterioration in the creditworthiness of Columbia’s customers or the failure of its customers to meet their contractual obligations could have an adverse effect on the Corporation’s business, results of operations, financial condition and growth plans.

Execution of Capital Projects

Columbia has embarked on a significant expansion of their pipeline systems. The Corporation’s ability to achieve targeted returns depends on delivering projects on time and on budget. Execution of these major projects can be affected by delays in permitting, development and/or construction which may impact capital costs. Additionally, there are certain termination rights within the shipping contracts which are triggered if milestones are not achieved by certain dates. The cost of executing these projects may be higher than budgeted. Cost overruns are partially borne by Columbia under the shipping contracts which will ultimately affect actual returns associated with the project or projects.

Aging Pipeline Systems

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. Columbia implements integrity management testing of the pipelines that its operates, including the Columbia Gulf and Columbia Gas Transmission pipelines and it repairs, remediates or replaces 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. TransCanada expects to invest significant capital over the next several years to replace aging infrastructure, including replacement of the relatively older pipe found on the Columbia Gas Transmission system. 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 have a material adverse impact on the Corporation’s financial condition and results of operation.

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Tax Treatment of Distribution

NiSource received an opinion from its counsel confirming the tax-free status of the distribution of Columbia common stock to NiSource stockholders (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 Columbia 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 could have an adverse effect on Columbia, NiSource or the Corporation. If the Distribution ultimately is determined to be taxable, NiSource would recognize gain in an amount equal to the excess of the fair market value of the shares of Columbia’s common stock distributed to NiSource stockholders on the date of the Distribution over NiSource’s tax basis in such shares as of such date. Under the terms of the Tax Allocation Agreement that Columbia entered into in connection with the Distribution (the “Tax Allocation Agreement”), in the event that the Distribution were determined to be taxable as the result of actions taken after the Distribution by Columbia or any of its subsidiaries, Columbia 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 Columbia nor NiSource were at fault, Columbia 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.

Indemnification Obligations and Assumption of Liabilities from the Distribution

Pursuant to the Separation and Distribution Agreement entered into between Columbia and NiSource in connection with the Distribution (the “Separation and Distribution Agreement”) and certain other agreements, NiSource agreed to indemnify Columbia from certain liabilities and Columbia agreed to indemnify NiSource for certain liabilities. Claims made against Columbia under such indemnities could have a significant adverse impact on the Corporation. Columbia negotiated all of its 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 Columbia. Pursuant to the Separation and Distribution Agreement, Columbia assumed all past, present and future liabilities (other than certain tax liabilities which will be governed by the Tax Allocation Agreement) related to Columbia’s business, and 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 Columbia may not reflect the allocation that would have been reached between two unaffiliated parties. In addition, Columbia has limited remedies under the Separation and Distribution Agreement. See Note 1A, “Company Structure and Basis of Presentation” in the audited consolidated financial statements of Columbia as at and for the years ended December 31, 2015 and 2014.

Third parties may seek to hold Columbia responsible for retained liabilities of NiSource. Under the agreements Columbia entered into with NiSource, NiSource agreed to indemnify Columbia for claims and losses relating to these retained liabilities. However, if those liabilities are significant and Columbia is ultimately held liable for them, it cannot be assured that the Corporation will be able to recover the full amount of Columbia’s losses from NiSource.

Under the Separation and Distribution Agreement, NiSource is obligated to indemnify Columbia for losses that a party may seek to impose upon Columbia or its 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 Columbia or its post-Separation affiliates, or losses that are attributable to NiSource in connection with the Separation or are not expressly assumed by Columbia under its agreements with NiSource. Immediately following the Separation, any claims made against Columbia that are properly attributable to NiSource in accordance with these arrangements would require Columbia to exercise its rights under its agreements with NiSource to obtain payment. Upon completion of the Acquisition, the Corporation is exposed to the risk that, in these circumstances, NiSource cannot, or will not, make the required payment.

Potential Treatment of Distribution as Fraudulent Conveyance

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

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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 Columbia, which could adversely affect the Corporation’s results of operations, cash flows and financial condition. Among other things, the court could require the Corporation, as shareholder of Columbia, to return to NiSource, for the benefit of its creditors, some or all of the shares of Columbia’s common stock issued in the Distribution, or require Columbia 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

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SCHEDULE B

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

COLUMBIA PIPELINE GROUP, INC.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Houston, Texas

We have audited the accompanying consolidated balance sheets of Columbia Pipeline Group, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and 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, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated and combined financial statements present fairly, in all material respects, the financial position of the Columbia Pipeline Group, Inc. as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

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

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

February 18, 2016

(February 22, 2016 as to Note 27)

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COLUMBIA PIPELINE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(in millions)	December 31, 2015			December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	930.9		$	0.5
Accounts receivable (less reserve of $0.6 and $0.6, respectively)	152.4			149.4
Accounts receivable-affiliated	—			180.0
Materials and supplies, at average cost	32.8			24.9
Exchange gas receivable	19.0			34.8
Deferred property taxes	52.0			48.9
Deferred income taxes	—			60.0
Prepayments and other	48.5			20.8
Total Current Assets	1,235.6			519.3
Investments
Unconsolidated affiliates	438.1			444.3
Other investments	13.8			2.7
Total Investments	451.9			447.0
Property, Plant and Equipment
Property, plant and equipment	9,052.3			7,935.4
Accumulated depreciation and amortization	(2,988.6		)	(2,976.8		)
Net Property, Plant and Equipment	6,063.7			4,958.6
Other Noncurrent Assets
Regulatory assets	177.7			151.9
Goodwill	1,975.5			1,975.5
Postretirement and postemployment benefits assets	115.7			90.0
Deferred charges and other	36.1			15.2
Total Other Noncurrent Assets	2,305.0			2,232.6
Total Assets	$	10,056.2		$	8,157.5

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

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COLUMBIA PIPELINE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)	December 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities
Current portion of long-term debt-affiliated	$	—		$	115.9
Short-term borrowings	15.0			—
Short-term borrowings-affiliated	—			252.5
Accounts payable	56.8			56.0
Accounts payable-affiliated	—			53.6
Customer deposits	17.9			13.4
Taxes accrued	106.0			103.2
Interest accrued	9.5			—
Exchange gas payable	18.6			34.7
Deferred revenue	15.0			22.5
Accrued capital expenditures	100.1			61.1
Accrued compensation and related costs	51.9			31.2
Other accruals	70.0			40.1
Total Current Liabilities	460.8			784.2
Noncurrent Liabilities
Long-term debt	2,746.2			—
Long-term debt-affiliated	—			1,472.8
Deferred income taxes	1,348.1			1,255.7
Accrued liability for postretirement and postemployment benefits	49.4			53.0
Regulatory liabilities	321.6			295.7
Asset retirement obligations	25.7			23.2
Other noncurrent liabilities	91.4			96.6
Total Noncurrent Liabilities	4,582.4			3,197.0
Total Liabilities	5,043.2			3,981.2
Commitments and Contingencies (Refer to Note 19)
Equity
Common stock, $0.01 par value, 2,000,000,000 shares authorized; 399,841,350 and no shares outstanding, respectively	4.0			—
Additional paid-in capital	4,032.7			—
Retained earnings	46.9			—
Net parent investment	—			4,210.8
Accumulated other comprehensive loss	(27.0		)	(34.5		)
Total CPG Equity	4,056.6			4,176.3
Noncontrolling Interest	956.4			—
Total Equity	5,013.0			4,176.3
Total Liabilities and Equity	$	10,056.2		$	8,157.5

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

B-3

COLUMBIA PIPELINE GROUP, INC.

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

Year Ended December 31, (in millions, except per share amounts)	2015			2014			2013
							Predecessor
Operating Revenues
Transportation revenues	$	1,054.4		$	990.8		$	850.9
Transportation revenues-affiliated	47.5			95.7			94.1
Storage revenues	171.4			144.0			142.8
Storage revenues-affiliated	26.2			53.2			53.6
Other revenues	35.4			64.3			39.1
Total Operating Revenues	1,334.9			1,348.0			1,180.5
Operating Expenses
Operation and maintenance	652.1			628.4			509.0
Operating and maintenance-affiliated	52.9			123.2			118.6
Depreciation and amortization	139.9			118.8			107.0
Gain on sale of assets and impairment, net	(52.9		)	(34.5		)	(18.6		)
Property and other taxes	75.3			67.1			62.2
Total Operating Expenses	867.3			903.0			778.2
Equity Earnings in Unconsolidated Affiliates	60.5			46.6			35.9
Operating Income	528.1			491.6			438.2
Other Income (Deductions)
Interest expense	(67.6		)	—			—
Interest expense-affiliated	(29.3		)	(62.0		)	(37.9		)
Other, net	29.3			8.8			17.9
Total Other Deductions, net	(67.6		)	(53.2		)	(20.0		)
Income from Continuing Operations before Income Taxes	460.5			438.4			418.2
Income Taxes	153.0			169.7			146.5
Income from Continuing Operations	$	307.5		$	268.7		$	271.7
(Loss) Income from Discontinued Operations-net of taxes	(0.4		)	(0.6		)	9.0
Net Income	$	307.1		$	268.1		$	280.7
Less: Net income attributable to noncontrolling interest	39.9
Net Income Attributable to CPG	$	267.2
Amounts Attributable to CPG:
Income from continuing operations	$	267.6		$	268.7		$	271.7
(Loss) Income from discontinued operations-net of taxes	(0.4		)	(0.6		)	9.0
Net Income Attributable to CPG	$	267.2		$	268.1		$	280.7
Basic Earnings Per Share
Continuing operations	$	0.81		$	0.84		$	0.86
Discontinued operations	—			—			0.03
Basic Earnings Per Share	$	0.81		$	0.84		$	0.89
Diluted Earnings Per Share
Continuing operations	$	0.81		$	0.84		$	0.86
Discontinued operations	—			—			0.03
Diluted Earnings Per Share	$	0.81		$	0.84		$	0.89
Basic Average Common Shares Outstanding	328.5			317.6			317.6
Diluted Average Common Shares	329.1			317.6			317.6
Dividends Declared Per Common Share	$	0.25		$	—		$	—

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

B-4

COLUMBIA PIPELINE GROUP, INC.

STATEMENTS OF CONSOLIDATED AND COMBINED COMPREHENSIVE INCOME

Year Ended December 31, (in millions, net of taxes)	2015		2014			2013
						Predecessor
Net Income	$	307.1	$	268.1		$	280.7
Other comprehensive income
Net unrealized gain on cash flow hedges(1)	0.2		1.0			1.1
Unrecognized pension and OPEB benefit (costs)(2)(3)	5.2		(9.7		)	8.2
Total other comprehensive income (loss)	5.4		(8.7		)	9.3
Total Comprehensive Income	312.5		259.4			290.0
Less: Comprehensive Income-noncontrolling interest	40.0		—			—
Comprehensive Income-controlling interests	$	272.5	$	259.4		$	290.0

(1)Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.2 million, $0.7 million and $0.6 million tax expense in 2015, 2014 and 2013, respectively.

(2)Unrecognized pension and other postretirement (“OPEB”) benefit (costs), net of $1.2 million tax benefit, $6.1 million tax benefit, and $5.3 million tax expense in 2015, 2014 and 2013, respectively.

(3)Unrecognized pension and OPEB costs are primarily related to pension and OPEB remeasurement recorded during 2015.

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

B-5

COLUMBIA PIPELINE GROUP, INC.

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

Year Ended December 31, (in millions)	2015			2014			2013
							Predecessor
Operating Activities
Net Income	$	307.1		$	268.1		$	280.7
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization	139.9			118.8			107.0
Deferred income taxes and investment tax credits	131.9			142.6			173.9
Deferred revenue	4.2			1.6			(7.8		)
Equity-based compensation expense and profit sharing contribution	9.4			6.3			2.2
Gain on sale of assets and impairment, net	(52.9		)	(34.5		)	(18.6		)
Equity earnings in unconsolidated affiliates	(60.5		)	(46.6		)	(35.9		)
Loss (income) from discontinued operations-net of taxes	0.4			0.6			(9.0		)
Amortization of debt related costs	3.1			—			—
AFUDC equity	(28.3		)	(11.0		)	(6.8		)
Distributions of earnings received from equity investees	57.2			37.8			32.1
Changes in Assets and Liabilities:
Accounts receivable	(17.4		)	(20.3		)	2.8
Accounts receivable-affiliated	34.7			(3.6		)	(10.1		)
Accounts payable	(5.0		)	2.8			5.5
Accounts payable-affiliated	(53.6		)	12.4			16.3
Customer deposits	(22.9		)	77.5			1.3
Taxes accrued	8.2			12.0			(33.8		)
Interest accrued	9.4			—			—
Exchange gas receivable/payable	(0.3		)	1.1			(0.5		)
Other accruals	50.2			0.9			0.8
Prepayments and other current assets	(27.1		)	(4.4		)	21.7
Regulatory assets/liabilities	20.2			9.0			42.6
Postretirement and postemployment benefits	(4.4		)	(1.3		)	(115.3		)
Deferred charges and other noncurrent assets	(16.3		)	(4.3		)	9.9
Other noncurrent liabilities	6.5			0.7			(15.6		)
Net Operating Activities from Continuing Operations	493.7			566.2			443.4
Net Operating Activities (used for) from Discontinued Operations	(0.2		)	(1.4		)	13.8
Net Cash Flows from Operating Activities	493.5			564.8			457.2
Investing Activities
Capital expenditures	(1,181.0		)	(747.2		)	(674.8		)
Insurance recoveries	2.1			11.3			6.4
Changes in short-term lendings-affiliated	145.5			(57.2		)	(3.2		)
Proceeds from disposition of assets	77.6			9.3			15.4
Contributions to equity investees	(1.4		)	(69.2		)	(125.5		)
Distributions from equity investees	16.0			—			—
Other investing activities	(27.4		)	(7.1		)	(9.2		)
Net Cash Flows used for Investing Activities	(968.6		)	(860.1		)	(790.9		)
Financing Activities
Change in short-term borrowings	15.0			—			—
Change in short-term borrowings-affiliated	(252.5		)	(467.1		)	391.0
Issuance of long-term debt	2,745.9			—			—
Debt related costs	(23.6		)	(6.4		)	—
Issuance of long-term debt-affiliated	1,217.3			768.9			65.1
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			—			—
Distribution of IPO proceeds to parent	(500.0		)	—			—
Distribution to parent	(1,450.0		)	—			(123.0		)
Distribution to noncontrolling interest	(23.2		)	—			—
Dividends paid — common stock	(79.5		)	—			—
Transfer from parent	0.8			—			—
Net Cash Flows from Financing Activities	1,405.5			295.4			333.1
Change in cash and cash equivalents	930.4			0.1			(0.6		)
Cash and cash equivalents at beginning of period	0.5			0.4			1.0
Cash and Cash Equivalents at End of Period	$	930.9		$	0.5		$	0.4

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

B-6

COLUMBIA PIPELINE GROUP, INC.

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(in millions)	Common Stock		Additional Paid-in Capital			Retained Earnings			Net Parent Investment			Accumulated Other Comprehensive Income (Loss)			Noncontrolling interest			Total
Balance as of January 1, 2013 — Predecessor	$	—	$	—		$	—		$	3,778.4		$	(35.1	)	$	—		$	3,743.3
Net Income	—		—			—			280.7			—			—			280.7
Other comprehensive income, net of tax	—		—			—			—			9.3			—			9.3
Dividends to parent	—		—			—			(123.0		)	—			—			(123.0		)
Net transfers from parent	—		—			—			5.3			—			—			5.3
Balance as of December 31, 2013 — 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			—			39.9			307.1
Other comprehensive income, net of tax	—		—			—			—			5.3			0.1			5.4
Allocation of AOCI to noncontrolling interest	—		—			—			—			2.2			(2.2		)	—
Issuance of common units of CPPL	—		—			—			—			—			1,168.4			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		)	—
Distributions to noncontrolling interest	—		—			—			—			—			(23.2		)	(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			—			—			—			0.5			1.5
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	—		—			(79.5		)	—			—			—			(79.5		)
Balance as of December 31, 2015	$	4.0	$	4,032.7		$	46.9		$	—		$	(27.0	)	$	956.4		$	5,013.0

(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.

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

B-7

COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 by NiSource Inc. (“NiSource”) 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 that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under a tariff 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 is 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 Corp. (“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

B-8

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.

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, Columbia OpCo and CPG. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline, and Pennant. All intercompany transactions and balances have been eliminated.

B.  Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

C.  Cash and Cash Equivalents.  Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.

D.  Allowance for Uncollectible Accounts.  The reserve for uncollectible receivables is 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.

B-9

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:

	2015				2014				2013
	Debt		Equity		Debt		Equity		Debt		Equity
									Predecessor
Columbia Gas Transmission	1.8	%	6.3	%	0.9	%	3.0	%	2.5	%	3.2	%
Columbia Gulf	2.9	%	6.3	%	2.1	%	9.4	%	2.5	%	3.2	%

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, 2015, 2014 and 2013. Please see Note 7, “Gain on Sale of Assets,” in the Notes to Consolidated and Combined Financial Statements for information regarding the sale of storage base gas in 2013. Gas stored-base gas is included in Property, plant and equipment on the Consolidated Balance Sheets.

H.  Amortization of Software Costs.  External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. CPG amortized $8.7 million in 2015, $4.3 million in 2014 and $5.0 million in 2013 related to software costs. CPG’s unamortized software balance was $59.8 million and $18.3 million at December 31, 2015 and 2014, respectively.

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 $2.4 million for the year ended December 31, 2015 and zero for the years ended December 31, 2014 and 2013.

K.  Revenue Recognition.  Revenue is recorded as services are performed. Revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.

B-10

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 $26.5 million, $43.8 million and $21.2 million for the years ended December 31, 2015, 2014 and 2013, respectively, and is included in “Other revenues” on the Statements of Consolidated and Combined Operations.

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 $52.3 million, $34.5 million and $7.3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in “Gain on sale of assets and impairment, net” on the Statements of Consolidated and Combined Operations.

L.  Earnings Per Share.  Basic EPS is based on net income attributable to CPG and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested awards that have not yet been issued as common stock. Diluted EPS includes the above, plus unvested stock awards granted under CPG’s compensation plans, but only to the extent these instruments dilute earnings per share.

On July 1, 2015, 317.6 million shares of CPG common stock were distributed to NiSource stockholders in conjunction with the Separation. For comparative purposes, and to provide a more meaningful calculation for weighted-average shares, CPG has assumed this amount to be outstanding as of the beginning of each period prior to the Separation presented in the calculation of weighted-average shares outstanding.

The calculation of diluted average common shares is as follows:

Year Ended December 31, (in millions)	2015	2014	2013
			Predecessor
Basic average common shares outstanding	328.5	317.6	317.6
Dilutive potential common shares:
Shares restricted under stock plans	0.6	—	—
Diluted weighted average shares outstanding	329.1	317.6	317.6

Dividends.  CPG paid a dividend of $0.125 per share to common stockholders on August 20, 2015. On August 4, 2015, CPG declared a dividend of $0.125 per share to common stockholders of record at October 30, 2015, payable November 20, 2015. On January 29, 2016, CPG declared a dividend of $0.12875 per share to common stockholders of record at February 8, 2016, payable February 19, 2016.

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M.  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.

N.  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.

O.  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 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.

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 2015, 2014 and 2013 were $5.8 million, $1.3 million and $5.3 million, respectively.

P.  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 19, “Other Commitments and Contingencies” in the Notes to Consolidated and Combined Financial Statements for further discussion.

Q.  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’

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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%. CPG accounts for the joint venture under the equity method of accounting.

R.  Natural Gas and Oil Properties.  CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method.

CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors.

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015 and 2014:

(in millions)	2015			2014
Beginning Balance	$	14.9		$	1.9
Additions pending the determination of proved reserves	1.3			20.1
Reclassifications of proved properties	(14.5		)	(7.1		)
Ending Balance	$	1.7		$	14.9

As of December 31, 2015, there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to one project initiated in 2013.

2.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, 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, 2015, 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:

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(in millions)	Year Ended December 31, 2015
Net income attributable to CPG	$	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	$	494.3

3.RECENT ACCOUNTING PRONOUNCEMENTS

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. ASU 2015-17 simplifies the presentation of deferred taxes by requiring that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet. CPG is required to adopt ASU 2015-17 for periods beginning after December 15, 2016, including interim periods, and the new standard is to be applied prospectively or retrospectively to all presented periods with early adoption permitted. On December 31, 2015 CPG prospectively adopted ASU 2015-17 in the Consolidated and Combined Financial Statements and 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 is required to adopt ASU 2015-03 and ASU 2015-15 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively with early adoption permitted. The adoption of ASU 2015-3 and ASU 2015-15 will result in a reclassification from “Deferred charges and other” to “Long-term debt” of the unamortized balance of debt issuance costs. At December 31, 2015, the balance of unamortized debt issuance costs recorded in “Deferred charges and other” was $20.6 million.

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. CPG is currently evaluating the impact the adoption of ASU 2014-09 and ASU 2015-14 will have on the Consolidated and Combined Financial Statements 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 is required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2015-02 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate that the impact will be material.

4.TRANSACTIONS WITH AFFILIATES

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:

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

4.TRANSACTIONS WITH AFFILIATES

Statement of Operations

	Year Ended December 31,
(in millions)	2015		2014		2013
					Predecessor
Transportation revenues	$	47.5	$	95.7	$	94.1
Storage revenues	26.2		53.2		53.6
Other revenues	0.2		0.3		0.3
Operation and maintenance expense	52.9		123.2		118.6
Interest expense	29.3		62.0		37.9
Interest income	2.5		0.7		0.7

Balance Sheet

(in millions)	December 31, 2015		December 31, 2014
Accounts receivable	$	—	$	180.0
Current portion of long term debt-affiliated	—		115.9
Short-term borrowings	—		252.5
Accounts payable	—		53.6
Long-term debt	—		1,472.8

Transportation, Storage and Other Revenues.  CPG provided natural gas transportation, storage and other services to subsidiaries of NiSource, which were deemed to be affiliates prior to the Separation.

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.

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, $61.6 million and $40.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, offset by associated AFUDC of $2.4 million, $2.7 million and $6.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the 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

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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 was 1.21% at June 30, 2015 and 0.70% at December 31, 2014, respectively. The interest expense for short-term borrowings charged for the years ended December 31, 2015, 2014 and 2013 was $0.7 million, $3.1 million and $4.1 million, respectively.

Accounts Receivable.  CPG included in accounts receivable amounts due from the money pool discussed above of $145.5 million at December 31, 2014 for subsidiaries in a net deposit position. Also included in the balance at December 31, 2014 are amounts due from subsidiaries of NiSource for transportation and storage services of $34.5 million. Net cash flows related to the money pool receivables, including the receipt of money pool deposits from NiSource at the time of Separation, are included as Investing Activities on the Statements of Consolidated and Combined Statements of Cash Flows. All other affiliated receivables are included as Operating Activities.

Short-term Borrowings.  The subsidiaries of CPG entered into an intercompany money pool agreement with NiSource Finance with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement is with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. The CPG revolving credit agreement became effective at the completion of the Separation with a termination date of July 2, 2020. Each of CEG, OpCo GP and Columbia OpCo is a guarantor of CPG’s revolving credit facility. As guarantors and restricted subsidiaries, CEG, OpCo GP and Columbia OpCo are subject to various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG not any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo’s partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At December 31, 2015, neither CPG nor its consolidated subsidiaries had any restricted net assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to CPG. CPG’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against Columbia OpCo as a guarantor.

The balance of Short-term Borrowings at December 31, 2014 of $252.5 million included those subsidiaries of CPG in a net borrower position of the NiSource Finance money pool discussed above. Net cash flows related to Short-term Borrowings, including the repayment of money pool borrowings to NiSource at the time of Separation, are included as Financing Activities on the Statements of Consolidated and Combined Statements of Cash Flows.

Accounts Payable.  The affiliated accounts payable balance primarily included amounts due for services received from NiSource Corporate Services and interest payable to NiSource Finance.

Long-term Debt.  CPG’s long-term financing requirements, prior to the private placement of seniors notes on May 22, 2015, were satisfied through borrowings from NiSource Finance. CPG used a portion of net

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proceeds from the senior notes to repay approximately $1,087.3 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource Finance. Details of the affiliated long-term debt balance are summarized in the table below:

Origination Date (in millions)	Interest Rate		Maturity Date	December 31, 2015		December 31, 2014
November 28, 2005(1)	5.41	%	November 30, 2015	$	—	$	115.9
November 28, 2005	5.45	%	November 28, 2016	—		45.3
November 28, 2005	5.92	%	November 28, 2025	—		133.5
November 28, 2012	4.63	%	November 28, 2032	—		45.0
November 28, 2012	4.94	%	November 30, 2037	—		95.0
December 19, 2012	5.16	%	December 21, 2037	—		55.0
November 28, 2012	5.26	%	November 28, 2042	—		170.0
December 19, 2012	5.49	%	December 18, 2042	—		95.0
December 9, 2013	4.75	%	December 31, 2016	—		834.0
Total Long-term Debt				$	—	$	1,588.7

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

Dividends.  Prior to the Separation, 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 and paid $123.0 million to NiSource in the year ended December 31, 2013. There were no restrictions on the payment by CPG of dividends to NiSource.

5.SHORT-TERM BORROWINGS

CPG Revolving Credit Facility.  On December 5, 2014, CPG entered into a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. The revolving credit facility became effective as of the Separation with a termination date of July 2, 2020. CPG expects that $750.0 million of this facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of this facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG’s $1,000.0 million commercial paper program.

Obligations under the CPG revolving credit facility are unsecured. Loans under the CPG revolving credit facility will bear interest at CPG’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent, (b) the reference prime rate of JPMorgan Chase Bank, N.A., or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (“LIBOR”), plus 1.000 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. CPG’s revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to CPG’s credit rating.

Revolving indebtedness under the CPG credit facility will rank equally with all of CPG’s outstanding unsecured and unsubordinated debt. CEG, OpCo GP and Columbia OpCo have each fully guaranteed the CPG credit facility. The CPG revolving credit facility contains various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making

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distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo’s partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At December 31, 2015, neither CPG nor its consolidated subsidiaries had any restricted net assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to CPG. The CPG revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million.

The CPG revolving credit facility also contains certain financial covenants that require CPG to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for any period of four consecutive fiscal quarters (each, a “test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017, and during a Specified Acquisition Period (as defined in the CPG revolving credit facility), the leverage ratio may not exceed 5.50 to 1.00.

A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against CPG or any guarantor.

As of December 31, 2015, CPG had no borrowings outstanding and had $18.1 million in letters of credit under the revolving credit facility.

CPPL Revolving Credit Facility.  On December 5, 2014, CPPL entered into a $500.0 million senior revolving credit facility, of which $50.0 million in letters of credit is available. The revolving credit facility became effective at the closing of CPPL’s IPO with a termination date of February 11, 2020. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls to Columbia OpCo.

CPPL’s obligations under the revolving credit facility are unsecured. The loans thereunder bear interest at CPPL’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the LIBOR, plus 1.000 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. The revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of CPG.

The revolving indebtedness under CPPL’s credit facility ranks equally with all CPPL’s outstanding unsecured and unsubordinated debt. CPG, CEG, OpCo GP and Columbia OpCo have each fully guaranteed CPPL’s credit facility.

CPPL’s revolving credit facility contains various covenants and restrictive provisions which, among other things, limit CPPL’s ability and CPPL’s restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of CPPL’s assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by CPPL’s organizational documents. The restricted payment provision does not prohibit CPPL or any of its restricted subsidiaries from making distributions in

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accordance with their respective organizational documents unless there has been an event of default (as defined in the CPPL revolving credit agreement), and neither CPPL nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. In particular, in accordance with CPPL’s partnership agreement, the general partner has adopted a policy that CPPL will make quarterly cash distributions in amounts equal to at least the minimum quarterly distribution of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. At December 31, 2015, neither CPPL nor its consolidated subsidiaries had any restricted net assets. If CPPL fails to perform the obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. CPPL’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness it may have with an outstanding principal amount in excess of $50.0 million.

The revolving credit facility also contains certain financial covenants that require CPPL to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the CPPL revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00.

A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against CPPL or any guarantor.

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

CPG Commercial Paper Program.  On October 5, 2015, CPG established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. CEG, OpCo GP and Columbia OpCo have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

Short-term borrowings were as follows:

At December 31, (in millions)	2015		2014
Commercial paper borrowings	$	—	$	—
CPG credit facility borrowings	—		—
CPPL credit facility borrowings, weighted average interest rate of 1.28% at December 31, 2015	15.0		—
Total Short-Term Borrowings	$	15.0	$	—

Given their maturity and turnover is less than 90 days, cash flows related to the borrowings and repayments of the items listed above 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 its private placement of $2,750.0 million in aggregated principal amount of its 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”),

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$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 Notes were issued at a discount, for net proceeds of approximately $2,722.3 million after deducting the Initial Purchasers’ discount and offering expenses of CPG.

Indenture.  The Notes are governed by an Indenture, dated as of May 22, 2015 (the “Indenture”), entered into by CPG and the certain subsidiary guarantors named therein (the “Guarantors”) with U.S. Bank National Association, as trustee (the “Trustee”).

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 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 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, commencing on December 1, 2015.

Registration Rights Agreement.  In connection with the private placement of the Notes, CPG and the Guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Initial Purchasers, pursuant to which CPG and the Guarantors agreed to file, and use their reasonable best efforts to cause to become effective, an exchange offer registration statement with the SEC and to consummate an exchange offer within 360 days after the date of issuance of the Notes pursuant to which holders of each series of the Notes can exchange the Notes issued in the offering for registered notes having the same terms as the Notes. Under certain circumstances set forth in the Registration Rights Agreement, in lieu of a registered exchange offer, CPG and the Guarantors must file, and use reasonable best efforts to cause to become effective, a shelf registration statement for the resale of the Notes. If CPG fails to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 0.50% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

The following table summarizes the outstanding long-term debt maturities at December 31, 2015.

Year Ending December 31, (in millions)
2016	$	—
2017	—
2018	500.0
2019	—
2020	750.0
After	1,500.0
Total(1)	$	2,750.0

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(1)This amount excludes unamortized discount of $3.8 million. The unamortized discount applicable to the Notes is 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, 2015, 2014 and 2013, gains on conveyances amounted to $52.3 million, $34.5 million and $7.3 million, respectively, and are included in “Gain on sale of assets and impairment, net” on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $35.8 million received by CEVCO from CNX Gas Company LLC during the year ended December 31, 2015, for the lease of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. As of December 31, 2015 and 2014, deferred gains of approximately $8.1 million and $19.6 million, respectively, were deferred pending performance of future obligations and recorded in “Deferred revenue” on the Consolidated Balance Sheets.

In 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million.

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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)	2015			2014
Property, plant and equipment
Pipeline and other transmission assets	$	6,160.4		$	5,333.0
Storage facilities	1,370.1			1,326.5
Gas stored base gas	299.5			299.5
Gathering and processing facilities	370.2			263.3
Construction work in process	487.6			454.2
General plant, software, and other assets	364.5			258.9
Property, plant and equipment	9,052.3			7,935.4
Accumulated depreciation and amortization	(2,988.6		)	(2,976.8		)
Net property, plant and equipment	$	6,063.7		$	4,958.6

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

	Year Ended December 31,
	2015	2014	2013
			Predecessor
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%-3.30%	2.19%-3.50%
Gathering and processing facilities	1.67%-2.50%	1.67%-2.50%	1.67%-2.50%
General plant, software, and other assets	1.00%-21.00%	1.00%-10.00%	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, 2015 and December 31, 2014 were $1,975.5 million.

The Predecessor completed a quantitative (“step 1”) fair value measurement of the reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded 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

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discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Predecessor utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated 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.

The Predecessor applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2015. For the current year test, the Predecessor assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The results of this assessment indicated that it is not more likely than not that 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. CPG reviewed the market capitalization method due to the recent decline in CPG’s share price. Following this review CPG determined there were no indicators that would require goodwill impairment testing subsequent to May 1, 2015.

10.ASSET RETIREMENT OBLIGATIONS

Changes in CPG’s liability for asset retirement obligations for the years 2015 and 2014 are presented in the table below:

(in millions)	2015			2014
Beginning Balance	$	23.2		$	26.3
Accretion expense	1.2			1.5
Additions	4.1			2.2
Settlements	—			(6.6		)
Change in estimated cash flows	(2.8		)	(0.2		)
Ending Balance	$	25.7		$	23.2

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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.

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)	2015		2014
Assets
Unrecognized pension benefit and other postretirement benefit costs	$	135.2	$	120.9
Other postretirement costs	9.0		10.8
Deferred taxes on AFUDC equity	35.4		21.8
Other	3.1		4.5
Total Regulatory Assets	$	182.7	$	158.0

At December 31, (in millions)	2015		2014
Liabilities
Cost of removal	$	154.7	$	157.6
Regulatory effects of accounting for income taxes	10.6		10.9
Unrecognized pension benefit and other postretirement benefit costs	0.7		8.3
Other postretirement costs	155.6		117.3
Other	1.2		2.9
Total Regulatory Liabilities	$	322.8	$	297.0

No regulatory assets are earning a return on investment at December 31, 2015. Regulatory assets of $35.6 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 7 years.

Assets:

Unrecognized pension benefit and other postretirement benefit costs — In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders to be recovered through base rates.

Other postretirement costs — Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.

Deferred taxes on AFUDC equity — ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. 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.

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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.

Unrecognized pension benefit and other postretirement benefit costs — In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the benefits as a regulatory liability in accordance with regulatory orders.

Other postretirement costs — Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the Predecessor’s results, which exceeds the amount funded in the plan.

Regulatory Matters

Columbia Gas Transmission Customer Settlement.  On January 24, 2013, the FERC approved the Settlement. In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter.

The Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25.0 million in revenues annually thereafter.

The Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system. The CCRM provides for a 14.0% revenue requirement with a portion designated as a recovery of taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100.0 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission’s transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15.0% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term.

On January 28, 2016, Columbia Gas Transmission received FERC approval of its December 2015 filing to recover costs associated with the third year of its comprehensive system modernization program. Total program adjusted spend to date is $937.1 million. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and

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improvements in control systems. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016.

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

Cost Recovery Trackers and other similar mechanisms.  Under section 4 of the NGA, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect.

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. During the year ended December 31, 2015, CPG had billed approximately $13.1 million for services and other costs to Millennium Pipeline. These investments are integral to CPG’s business. Contributions are made to these equity investees to fund CPG’s share of projects.

The following is a list of CPG’s equity method investments at December 31, 2015:

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

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.

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Year Ended December 31, (in millions)	2015		2014			2013
						Predecessor
Millennium Pipeline
Statement of Income Data:
Net Revenues	$	206.3	$	190.5		$	157.8
Operating Income	136.1		128.8			101.3
Net Income	98.0		89.6			63.0
Balance Sheet Data:
Current Assets	35.7		32.1			38.3
Noncurrent Assets	987.1		1,016.3			1,033.8
Current Liabilities	44.4		42.6			58.8
Noncurrent Liabilities	535.8		568.3			599.7
Total Members’ Equity	442.6		437.5			413.6
Contribution/Distribution Data:(1)
Contributions to Millennium Pipeline	1.4		2.6			16.6
Distribution of earnings from Millennium Pipeline	47.5		35.6			29.0
Hardy Storage
Statement of Income Data:
Net Revenues	$	23.4	$	23.6		$	24.4
Operating Income	15.3		16.1			16.5
Net Income	10.3		10.6			10.6
Balance Sheet Data:
Current Assets	12.1		12.0			12.5
Noncurrent Assets	155.5		157.4			160.2
Current Liabilities	19.3		17.1			18.3
Noncurrent Liabilities	68.5		77.4			85.7
Total Members’ Equity	79.8		74.9			68.7
Contribution/Distribution Data:(1)
Contributions to Hardy Storage	—		—			—
Distribution of earnings from Hardy Storage	2.6		2.2			3.1
Pennant
Statement of Income Data:
Net Revenues	$	34.6	$	8.5		$	2.0
Operating Income (Loss)	17.8		(2.4		)	1.3
Net Income (Loss)	17.8		(2.4		)	1.3
Balance Sheet Data:
Current Assets	11.0		23.7			34.1
Noncurrent Assets	389.6		380.0			231.9
Current Liabilities	8.4		8.6			11.4
Total Members’ Equity	392.2		395.1			254.6
Contribution/Distribution Data:(1)
Contributions to Pennant	—		66.6			108.9
Distribution of earnings from Pennant	7.1		—			—
Return of capital from Pennant	16.0		—			—

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

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

13.INCOME TAXES

The components of income tax expense were as follows:

Year Ended December 31, (in millions)	2015		2014			2013
						Predecessor
Income Taxes
Current
Federal	$	12.1	$	19.5		$	(15.5	)
State	9.1		7.6			(11.9		)
Total Current	21.2		27.1			(27.4		)
Deferred
Federal	120.2		119.2			157.4
State	11.6		23.5			16.6
Total Deferred	131.8		142.7			174.0
Deferred Investment Credits	—		(0.1		)	(0.1		)
Total Income Taxes	$	153.0	$	169.7		$	146.5

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)	2015					2014					2013
														Predecessor
Book income from Continuing Operations before income taxes	$	460.5				$	438.4				$	418.2
Tax expense at statutory federal income tax rate	161.2			35.0	%	153.5			35.0	%	146.4			35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	13.4			2.9		20.3			4.6		3.0			0.7
Noncontrolling interest	(14.0		)	(3.0	)	—			—		—			—
AFUDC-Equity	(9.2		)	(2.0	)	(3.7		)	(0.8	)	(2.4		)	(0.6	)
Other, net	1.6			0.3		(0.4		)	(0.1	)	(0.5		)	(0.1	)
Total Income Taxes	$	153.0		33.2	%	$	169.7		38.7	%	$	146.5		35.0	%

The effective income tax rates were 33.2%, 38.7% and 35.0% in 2015, 2014 and 2013, respectively. 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.

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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.

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.

On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 (“ATRA”). ATRA, among other things, extended retroactively the research credit under Internal Revenue Code section 41 until December 31, 2013, and also extended and modified 50% bonus depreciation for 2013. CPG recorded the effects of ATRA in the first quarter 2013.

In November 2015, the FASB issued Accounting Standard Update (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’s Consolidated Balance Sheet reflects prospective early adoption of ASU 2015-17. The December 31, 2015 accumulated deferred income taxes is presented with application of ASU 2015-17, and is presented on the Consolidated Balance Sheet as a noncurrent liability. The December 31, 2014 balances were not restated.

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)	2015			2014
Deferred tax liabilities
Accelerated depreciation and other property differences	$	1,429.2		$	1,235.2
Pension and other postretirement/postemployment benefits	29.9			27.7
Other regulatory assets	71.8			62.8
Equity method investments	124.3			99.2
Total Deferred Tax Liabilities	1,655.2			1,424.9
Deferred tax assets
Other regulatory liabilities	(126.8		)	(116.7		)
Net operating loss carryforward	(141.4		)	(70.3		)
Other	(38.9		)	(42.2		)
Total Deferred Tax Assets	(307.1		)	(229.2		)
Net Deferred Tax Liabilities	1,348.1			1,195.7
Less: Deferred income taxes related to current assets and liabilities	—			(60.0		)
Non-Current Deferred Tax Liability	$	1,348.1		$	1,255.7

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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 $127.7 million Federal carryforward will expire in various tax years from 2033 through 2035 and the $13.7 million state net operating loss benefit carryforward will expire in various tax years from 2028 through 2035.

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is a $0.4 million decrease for December 31, 2015, zero for December 31, 2014 and a $0.1 million increase for December 31, 2013. CPG recognizes accrued interest on 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, 2015, 2014 and 2013, 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, 2015, federal income tax years through 2013 have been audited and are effectively closed to further assessment, except for immaterial carryforward amounts. The audit of NiSource’s 2014 and 2015 consolidated federal tax return began in 2014 and 2015, respectively.

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, 2015, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

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 grantor 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 grantor 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. Other assets such as private equity funds may be used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the

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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.

In 2012, an asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, real estate, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by the projected benefit obligations of the qualified pension plans divided by the market value of qualified pension plan assets). The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on December 31, 2015 are as follows:

Asset Mix Policy of Funds:

	Defined Benefit Pension Plan				Postretirement Benefit Plan
Asset Category	Minimum		Maximum		Minimum		Maximum
Domestic Equities	25	%	45	%	35	%	55	%
International Equities	15	%	25	%	15	%	25	%
Fixed Income	23	%	37	%	20	%	50	%
Real Estate/Private Equity/Hedge Funds	0	%	15	%	0	%	0	%
Short-Term Investments	0	%	10	%	0	%	10	%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2015 and December 31, 2014:

	Defined Benefit Pension Plan Assets				Postretirement Benefit Plan Assets
December 31, 2015 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	%

	Defined Benefit Pension Plan Assets				Postretirement Benefit Plan Assets
December 31, 2014 Asset Class	Asset Value		% of Total Assets		Asset Value		% of Total Assets
	(in millions)				(in millions)
Domestic Equities	$	144.2	41.1	%	$	105.7	47.2	%
International Equities	63.3		18.1	%	41.2		18.4	%
Fixed Income	120.9		34.4	%	76.3		34.1	%
Real Estate/Private Equity/Hedge Funds	17.7		5.0	%	—		—	%
Cash/Other	4.9		1.4	%	0.6		0.3	%
Total	$	351.0	100.0	%	$	223.8	100.0	%

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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, 2015 and 2014. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total CPG Pension Plan Trust and OPEB investment assets at fair value classified within Level 3 were zero and $17.6 million as of December 31, 2015 and December 31, 2014, respectively. Such amounts were approximately zero and 3% of the CPG Pension Plan Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2015 and 2014, respectively.

Valuation Techniques Used to Determine Fair Value:

Level 1 Measurements

Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.

Level 2 Measurements

Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.

Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are classified as Level 2. The funds’ underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments.

Level 3 Measurements

Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds’ underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods.

The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days’ notice. Private equity investment strategies include buy-out, venture capital, growth

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equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships.

Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership’s fair value as recorded in the partnerships’ audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation.

For the year ended December 31, 2015, there were no significant changes to valuation techniques to determine the fair value of CPG’s pension and other postretirement benefits’ assets.

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	31.1			—		31.1		—
U.S. equities	141.0			—		141.0		—
International equities	55.6			—		55.6		—
Fixed income	100.9			—		100.9		—
Pension plan assets subtotal	357.6			7.5		350.1		—
Other postretirement benefit plan assets
Commingled funds
Short-term money markets	7.3			—		7.3		—
U.S. equities	13.9			—		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		21.2		—
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	$	371.3	$	—

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(1)This class represents pending trades with brokers.

The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2015:

(in millions)	Balance at January 1, 2015		Total gains or losses (unrealized / realized)		Purchases		(Sales)		Transfers into/(out of) level 3		Separation Allocation(1)			Balance at December 31, 2015
Fixed income securities
Other fixed income	$	0.1	$	—	$	—	$	—	$	—	$	(0.1	)	$	—
Private equity limited partnerships
U.S. multi-strategy	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.

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

14.PENSION AND OTHER POSTRETIREMENT BENEFITS

Fair Value Measurements at December 31, 2014:

Fair Value Measurements (in millions)	December 31, 2014			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Pension plan assets
Cash	$	2.6		$	2.6	$	—	$	—
Equity securities
U.S. equities	0.1			0.1		—		—
International equities	20.3			20.2		0.1		—
Fixed income securities
Government	17.8			15.7		2.1		—
Corporate	38.7			—		38.7		—
Mortgages/Asset backed securities	0.4			—		0.4		—
Other fixed income	0.1			—		—		0.1
Commingled funds
Short-term money markets	4.9			—		4.9		—
U.S. equities	144.2			—		144.2		—
International equities	42.1			—		42.1		—
Fixed income	61.6			—		61.6		—
Private equity limited partnerships
U.S. multi-strategy(1)	8.5			—		—		8.5
International multi-strategy(2)	5.3			—		—		5.3
Distressed opportunities	1.1			—		—		1.1
Real Estate	2.6			—		—		2.6
Pension plan assets subtotal	350.3			38.6		294.1		17.6
Other postretirement benefit plan assets
Commingled funds
Short-term money markets	0.8			—		0.8		—
U.S. equities	14.3			—		14.3		—
Mutual funds
U.S. equities	91.3			91.3		—		—
International equities	41.2			41.2		—		—
Fixed income	76.2			76.2		—		—
Other postretirement benefit plan assets subtotal	223.8			208.7		15.1		—
Due to brokers, net(3)	(0.1		)
Accrued investment income/dividends	0.1
Net receivables	0.7
Total pension and other postretirement benefit plan assets	$	574.8		$	247.3	$	309.2	$	17.6

(1)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily in the United States.

(2)This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

(3)This class represents pending trades with brokers.

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The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2014:

(in millions)	Balance at January 1, 2014		Total gains or losses (unrealized / realized)			Purchases		(Sales)			Transfers into/(out of) level 3		Balance at December 31, 2014
Fixed income securities
Other fixed income	$	—	$	—		$	0.1	$	—		$	—	$	0.1
Private equity limited partnerships
U.S. multi-strategy	8.7		0.4			0.4		(1.0		)	—		8.5
International multi-strategy	5.8		(0.1		)	0.1		(0.5		)	—		5.3
Distress opportunities	1.4		0.1			—		(0.4		)	—		1.1
Real estate	3.0		0.3			—		(0.7		)	—		2.6
Total	$	18.9	$	0.7		$	0.6	$	(2.6	)	$	—	$	17.6

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)	2015			2014			2015			2014
Change in projected benefit obligation(1)
Benefit obligation at beginning of year	$	397.6		$	376.7		$	124.2		$	120.9
Service cost	5.9			4.8			1.0			1.1
Interest cost	15.0			15.7			4.7			5.2
Plan participants’ contributions	—			—			2.3			3.0
Actuarial loss (gain)	(6.9		)	22.7			(12.4		)	5.7
Benefits paid	(29.7		)	(22.3		)	(9.8		)	(12.4		)
Estimated benefits paid by incurred subsidy	—			—			0.3			0.7
Transfer of participant balances from NiSource plans(2)	22.6			—			1.8			—
Projected benefit obligation at end of year	$	404.5		$	397.6		$	112.1		$	124.2
Change in plan assets
Fair value of plan assets at beginning of year	$	351.0		$	344.5		$	223.8		$	209.7
Actual return on plan assets	1.2			21.1			(2.5		)	11.6
Employer contributions	20.0			7.7			13.5			11.9
Plan participants’ contributions	—			—			2.3			3.0
Benefits paid	(29.7		)	(22.3		)	(9.8		)	(12.4		)
Transfer of participant balances from NiSource plans(2)	15.3			—			0.9			—
Fair value of plan assets at end of year	$	357.8		$	351.0		$	228.2		$	223.8
Funded status at end of year	$	(46.7	)	$	(46.6	)	$	116.1		$	99.6
Amounts recognized in the balance sheet consist of:
Noncurrent assets	$	—		$	—		$	116.1		$	113.1
Current liabilities	(0.8		)	—			—			—
Noncurrent liabilities	(45.9		)	(46.6		)	—			(13.5		)
Net amount recognized at end of year(3)	$	(46.7	)	$	(46.6	)	$	116.1		$	99.6
Amounts recognized in AOCI or regulatory assets/liabilities(4)
Unrecognized prior service credit	$	(3.7	)	$	(4.7	)	$	(2.0	)	$	(2.6	)
Unrecognized actuarial loss (gain)	164.5			148.7			(3.9		)	(12.5		)
Total recognized AOCI or regulatory assets/liabilities	$	160.8		$	144.0		$	(5.9	)	$	(15.1	)

(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.

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(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 $135.2 million and $0.7 million, respectively, as of December 31, 2015, and $120.9 million and $8.3 million, respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss.

CPG’s accumulated benefit obligation for its pension plans was $404.5 million and $397.6 million as of December 31, 2015 and 2014, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels.

CPG’s pension plans were underfunded by $46.7 million at December 31, 2015, compared to being underfunded by $46.6 million at December 31, 2014. CPG contributed $20.0 million and $7.7 million to its pension plans in 2015 and 2014, respectively.

During 2015, CPG’s funded status for its other postretirement benefit plans improved by $16.5 million to an overfunded status of $116.1 million primarily due to favorable claims experience and the implementation of new mortality assumptions released by the Society of Actuaries in 2014, offset by unfavorable asset returns. CPG contributed approximately $13.5 million and $11.9 million to its other postretirement benefit plans in 2015 and 2014, 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 2016.

In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plans’ 2013 service cost plus interest cost and, therefore, settlement accounting was required. As a result, the Predecessor recorded a settlement charge of $13.8 million in 2013. The Predecessor’s net periodic pension benefit cost for 2013 was decreased by $1.3 million as a result of the interim remeasurements.

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

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015		2014
Weighted-average assumptions to Determine Benefit Obligation
Discount Rate	4.05	%	3.64	%	4.29	%	3.96	%
Rate of Compensation Increases	4.00	%	4.00	%
Health Care Trend Rates
Trend for Next Year					8.39	%	6.90	%
Ultimate Trend					4.50	%	4.50	%
Year Ultimate Trend Reached					2022		2021

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(in millions)	1% point increase		1% point decrease
Effect on service and interest components of net periodic cost	$	0.1	$	(0.1	)
Effect on accumulated postretirement benefit obligation	3.1		(2.8		)

CPG expects to make contributions of approximately $0.8 million to its pension plans and approximately $2.2 million to its postretirement medical and life plans in 2016.

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

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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)
2016	$	34.9	$	8.2	$	0.6
2017	33.9		8.0		0.6
2018	35.1		8.0		0.6
2019	35.8		7.9		0.6
2020	37.1		7.9		0.5
2021-2025	175.3		37.4		1.7

The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
(in millions)	2015			2014			2013			2015			2014			2013
							Predecessor									Predecessor
Components of Net Periodic Benefit Cost (Income)
Service cost	$	5.9		$	4.8		$	4.9		$	1.0		$	1.1		$	1.5
Interest cost	15.0			15.7			14.6			4.7			4.6			5.4
Expected return on assets	(28.2		)	(27.3		)	(25.5		)	(18.1		)	(16.6		)	(13.8		)
Amortization of prior service (credit) cost	(1.1		)	(1.1		)	(1.1		)	(0.3		)	0.1			0.1
Recognized actuarial loss (gain)	9.9			7.5			12.3			(0.3		)	—			1.0
Net Periodic Benefit Cost (Income)	1.5			(0.4		)	5.2			(13.0		)	(10.8		)	(5.8		)
Settlement loss	—			—			13.8			—			—			—
Total Net Periodic Benefit Cost (Income)	$	1.5		$	(0.4	)	$	19.0		$	(13.0	)	$	(10.8	)	$	(5.8	)

The $1.9 million increase in the actuarially-determined pension benefit cost (income) is due primarily to the transfer of additional pension plan participants to CPGSC upon Separation from NiSource, decreased discount rates and unfavorable asset returns in 2015 compared to 2014. For its other postretirement benefit plans, CPG recognized $13.0 million in net periodic benefit income in 2015 compared to net periodic benefit income of $10.8 million in 2014 due primarily to favorable claims experience, offset by a decrease in discount rates in 2015 compared to 2014.

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
	2015		2014		2013		2015		2014		2013
					Predecessor						Predecessor
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
Discount Rate	3.84	%	4.34	%	3.36	%	4.10	%	4.76	%	3.92	%
Expected Long-Term Rate of Return on Plan Assets	8.20	%	8.30	%	8.30	%	8.05	%	8.14	%	8.17	%
Rate of Compensation Increases	4.00	%	4.00	%	4.00	%

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CPG believes it is appropriate to assume an 8.20% and 8.05% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2015 pension benefits cost. This is primarily based on asset mix and historical rates of return.

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

	Pension Benefits						Other Postretirement Benefits
(in millions)	2015			2014			2015			2014
Other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory assets or liabilities
Net actuarial loss	$	25.6		$	28.9		$	8.6		$	11.8
Less: amortization of prior service (credit) cost	1.1			1.1			0.3			(0.1		)
Less: amortization of net actuarial (gain) loss	(9.9		)	(7.5		)	0.3			—
Total recognized in other comprehensive income or regulatory assets or liabilities	$	16.8		$	22.5		$	9.2		$	11.7
Amount recognized in net periodic benefit cost and other comprehensive income or regulatory assets or liabilities	$	18.3		$	22.1		$	(3.8	)	$	0.9

Based on a December 31 measurement date, the net unrecognized actuarial loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2016 for the pension plans are $12.4 million, $(1.2) million and zero, respectively, and for other postretirement benefit plans are $0.2 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 and long-term debt-affiliated are recorded at historical amounts.

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

15.FAIR VALUE

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 and Long-term debt-affiliated.  The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2015 and 2014, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

The carrying amount and estimated fair values of financial instruments were as follows:

At December 31, (in millions)	Carrying Amount 2015		Estimated Fair Value 2015		Carrying Amount 2014		Estimated Fair Value 2014
Current portion of long-term debt-affiliated	$	—	$	—	$	115.9	$	120.0
Long-term debt	2,746.2		2,592.1		—		—
Long-term debt-affiliated	—		—		1,472.8		1,550.4

16.AUTHORIZED PREFERRED STOCK

CPG has 80,000,000 authorized shares of preferred stock with a $0.01 par value.

As of December 31, 2015, CPG had no preferred shares outstanding. All of CPG’s retained earnings at December 31, 2015 are free of restrictions.

17.COMMON STOCK

As of December 31, 2015, CPG had 2,000,000,000 authorized shares of common stock with a $0.01 par value.

Common Stock Offering.  On December 7, 2015, CPG completed the sale of 82,225,000 shares of common stock, including 10,725,000 shares of common stock that were issued pursuant to the exercise in full of the underwriters’ over-allotment option. CPG received net proceeds of $1,394.7 million, net of underwriting discounts and estimated offering expenses of approximately $44.2 million.

Common Stock Dividends.  Holders of shares of CPG’s common stock are entitled to receive dividends when, as and if declared by the board of directors out of funds legally available for that purpose. CPG paid quarterly common dividends totaling $0.25 per share for the year ended December 31, 2015. At its January 29, 2016 meeting, the board of directors declared a $0.12875 per share quarterly common dividend, payable on February 19, 2016 to holders of record on February 8, 2016.

18.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.

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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 provides 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. The Omnibus Plan provides that the number of shares of common stock of CPG available for awards is 8,000,000. At December 31, 2015, there were 5,513,260 shares reserved for future awards under the Omnibus Plan.

CPG recognized stock-based employee compensation expense of $7.9 million, $4.4 million and $1.1 million, during 2015, 2014 and 2013, respectively, as well as related tax benefits of $2.9 million, $1.6 million and $0.4 million, respectively.

As of December 31, 2015, the total remaining unrecognized compensation cost related to nonvested awards amounted to $21.0 million, which will be amortized over the weighted-average remaining requisite service period of 2.0 years.

Restricted Stock Units and Restricted Stock.  In 2015, CPG granted restricted stock units and shares of restricted stock of 130,160, 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. As of December 31, 2015, 129,665 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2015 award.

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. As of December 31, 2015, 450,107 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2015 award.

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. As of December 31, 2015, 198,532 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2014 award.

In 2013, NiSource granted restricted stock units and shares of restricted stock that were converted into 31,655 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 $0.5 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. As of December 31, 2015, 30,087 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2013 award.

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If the employee terminates employment before the service conditions lapse under the 2013, 2014 and 2015 awards due to (1) Retirement or Disability (as defined in the award agreement), or (2) death, the service conditions will lapse on the date of such termination with respect to a pro rata portion of the restricted stock units and shares of restricted stock. In the event of a Change-in-Control (as defined in the award agreement), all unvested shares of restricted stock and restricted stock units awarded prior to 2015 will immediately vest upon termination of employment occurring in connection with a change-in-control. Termination due to any other reason will result in all unvested shares of restricted stock and restricted stock units awarded being forfeited effective on the employee’s date of termination.

	Restricted Stock Units		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2014	230,187		$	20.27
Performance shares converted to restricted shares at Separation	1,460,401		15.66
Granted	580,267		26.29
Forfeited	(495	)	28.25
Vested	(1,568	)	18.24
Nonvested and Expected to Vest at December 31, 2015	2,268,792		$	18.85

Performance Shares.  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. The performance condition is based on achievement of relative total stockholder return, a non-GAAP financial measure that CPG defines as the annualized growth in dividends and share price as a share of CPG’s common stock (calculated using a 20 trading day average of CPG’s closing price, over a period beginning July 31, 2015 and ending on June 30, 2018) compared to the total stockholder return performance of a predetermined peer group of companies. The service conditions lapse on July 12, 2018 when the shares vest provided the performance criteria is satisfied. As of December 31, 2015, 161,504 nonvested performance shares were granted and outstanding of the 2015 award.

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. The service conditions lapse on February 28, 2017, when the shares vest. As of December 31, 2015, 586,219 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2014 award.

In 2013, NiSource granted performance shares that were converted to 874,182 CPG restricted stock units at Separation, subject to performance and service conditions. The grant date fair-value of the awards 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 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. The service conditions lapsed on January 30, 2016 when the shares vested. As of December 31, 2015, 874,182 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding for the 2013 award.

If the employee terminates employment before the performance and service conditions lapse under the 2013, 2014 and 2015 awards due to (1) Retirement or Disability (as defined in the award agreement), or (2) death, the employment conditions will lapse with respect to a pro rata portion of the performance shares payable at target on the date of termination provided the performance criteria are met. In the event of a Change-in-Control (as defined in the award agreement), all unvested performance shares will immediately vest. Termination due to any other reason will result in all performance shares awarded being forfeited effective on the employee’s date of termination.

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	Contingent Awards		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2014	1,460,401		$	15.66
Performance shares converted to restricted shares at Separation	(1,460,401	)	15.66
Granted	161,504		28.16
Forfeited	—		—
Vested	—		—
Nonvested and Expected to Vest at December 31, 2015	161,504		$	28.16

Non-employee Director Awards.  Currently, restricted stock units are 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 vest 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 are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. As of December 31, 2015, a total of 52,035 units are outstanding to non-employee directors under the Omnibus Plan. Of these awards, 13,495 were granted under the NiSource Plan and converted into 21,399 CPG units while the remaining 30,636 were granted by CPG subsequent to the Separation.

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 shall be distributed to the directors upon their separation from CPG’s board of directors or such later date as elected. As of December 31, 2015, 226,908 restricted stock units remain outstanding.

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 payable in shares of common stock to eligible employees based on earnings results; and eligible employees hired after January 1, 2010, receive a non-elective company contribution of three percent of eligible pay. For the years ended December 31, 2015, 2014 and 2013, CPG recognized 401(k) match, profit sharing and non-elective contribution expense of $9.8 million, $8.4 million and $6.1 million, respectively.

19.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, 2015 and the years in which they expire were:

(in millions)	Total		2016		2017		2018		2019		2020		After
Letters of credit	$	18.1	$	18.1	$	—	$	—	$	—	$	—	$	—
Other guarantees	45.7		0.6		2.0		—		—		—		43.1
Total commercial commitments	$	63.8	$	18.7	$	2.0	$	—	$	—	$	—	$	43.1

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. CPG does not anticipate its subsidiaries will have any difficulty maintaining compliance.

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Lines and Letters of Credit.  CPG maintains a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. CPG expects that $750.0 million of this facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of this facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG’s $1,000.0 million commercial paper program. As of December 31, 2015, CPG had no borrowings outstanding and $18.1 million in letters of credit outstanding under its revolving credit facility. CPPL maintains a $500.0 million senior revolving credit facility, of which $50.0 million is available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures, and the funding of capital calls. As of December 31, 2015, CPPL had $15.0 million in outstanding borrowings and no letters of credit under its revolving credit facility.

CPG has established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. CEG, OpCo GP and Columbia OpCo have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

Other Guarantees or Obligations.  CPG has purchase and sale agreement guarantees totaling $45.7 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.

CPG has on deposit a letter of credit with MUFG Union Bank, N.A., Collateral Agent, in a debt service reserve account in association with Millennium Pipeline’s notes as required under the Deposit and Disbursement Agreement that governs the Millennium Pipeline notes. This account is to be drawn upon by the note holders in the event that Millennium Pipeline is delinquent on its principal and interest payments. The value of CPG’s letter of credit represents 47.5% (CPG’s ownership interest in Millennium Pipeline) of the debt service reserve account requirement, or $16.2 million. The total exposure for CPG is $16.2 million. CPG has an accrued liability of $1.5 million related to the inception date fair value of this guarantee as of December 31, 2015.

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, 2015, tax years through 2013 have been audited and are effectively closed to further assessment, except for immaterial carryforward amounts. The audit of tax years 2014 and 2015 under the Compliance Assurance Program (“CAP”) is in process. As of December 31, 2015, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

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CPG is currently being audited for sales and use tax compliance in the state of Louisiana, New York, 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.

C.  Environmental Matters.  CPG’s operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. CPG believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary material permits to conduct its operations.

It is 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, 2015 and 2014, CPG has liabilities recorded of approximately $8.3 million and $14.3 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.

The following NAAQS were recently added or modified:

Ozone:  On October 1, 2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 ppb under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is required to include an adequate margin of safety in establishing the primary ozone standard for protection of public health, whereas the secondary ozone standard is intended to improve protection for trees, plants and ecosystems. The final rule becomes effective sixty days after the rule is published in the Federal Register. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With the EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations. Based on the current version of the rule, CPG does not expect a material impact on its operations.

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Nitrogen Dioxide (NO2):  The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing CPG combustion sources may need to be assessed and mitigated. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

Climate Change.  The EPA has already promulgated regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the U.S. on an annual basis. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.

New Source Performance Standards:  On August 18, 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. Semiannual leak detection and repair requirements using optical gas imaging are proposed for all components at new or existing compressor stations. Existing compressor stations trigger leak detection and repair requirements if any unit at the facility is modified. The EPA proposed additional requirements for any new or modified centrifugal or reciprocating compressors. Replacement of wet seals with dry seals or demonstrating a 95% reduction of methane emissions from wet seals is proposed for centrifugal compressors and rod packing replacement for reciprocating compressors is proposed every 26,000 hours of operation or every three years. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

Waste

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 $6.5 million and $12.5 million at December 31, 2015 and 2014, 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 $1.8 million at December 31, 2015 and 2014. The liability represents CPG’s best estimate of the cost to remediate the facilities.

D.  Operating Lease Commitments.  CPG leases assets in several areas of its operations. Payments made in connection with operating leases were $21.2 million in 2015, $14.9 million in 2014 and $13.3 million in 2013, and are primarily charged to operation and maintenance expense as incurred.

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)
2016	$	5.4
2017	6.7
2018	6.2
2019	5.5
2020	5.4
After	24.7
Total future minimum payments	$	53.9

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(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 2016 to 2025, 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, 2015, CPG expects to pay approximately $165.3 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, 2015, were:

(in millions)	Pipeline Service Agreements		IBM Service Agreement
2016	$	51.5	$	38.6
2017	49.5		33.0
2018	42.0		31.7
2019	25.4		31.0
2020	24.2		31.0
After	66.8		—
Total future minimum payments	$	259.4	$	165.3

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20.ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:

(in millions)	Gains and Losses on Cash Flow Hedges(1)			Pension and OPEB Items(1)			Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2013 — Predecessor	$	(18.7	)	$	(16.4	)	$	(35.1	)
Other comprehensive income before reclassifications	—			6.5			6.5
Amounts reclassified from accumulated other comprehensive income	1.1			1.7			2.8
Net current-period other comprehensive income	1.1			8.2			9.3
Balance as of December 31, 2013 — 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	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	)

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

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COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

20.ACCUMULATED OTHER COMPREHENSIVE LOSS

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 $14.3 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 $14.3 million and $16.6 million at December 31, 2015 and December 31, 2014, respectively, is included in unrealized losses on cash flow hedges above.

21.OTHER, NET

Year Ended December 31, (in millions)	2015		2014			2013
						Predecessor
AFUDC Equity	$	28.3	$	11.0		$	6.8
Miscellaneous(1)	1.0		(2.2		)	11.1
Total Other, net	$	29.3	$	8.8		$	17.9

(1)Miscellaneous primarily consists of a gain from insurance proceeds in 2013.

22.INTEREST EXPENSE

Year Ended December 31, (in millions)	2015			2014		2013
						Predecessor
Interest on long-term debt	$	67.5		$	—	$	—
Interest on short-term borrowings(1)	1.4			—		—
Debt discount/cost amortization	3.1			—		—
Allowance for funds used during construction	(6.8		)	—		—
Other	2.4			—		—
Total Interest Expense(2)	$	67.6		$	—	$	—

(1)Refer to Note 5, “Short-Term Borrowings” for additional information.

(2)Refer to Note 4, “Transactions with Affiliates” for a discussion of interest expense-affiliated for the year ended December 31, 2014 and 2013.

23.SEGMENTS OF BUSINESS

Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The CPG Chief Executive Officer is the chief operating decision maker for the periods presented.

B-49

At December 31, 2015, 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.

24.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, 2015, 2014 and 2013:

Year Ended December 31, (in millions)	2015		2014		2013
					Predecessor
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities(1)	$	128.4	$	78.5	$	53.1
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	96.9	$	53.6	$	38.4
Cash paid for income taxes(2)	32.3		21.2		15.3

(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.

25.CONCENTRATION OF CREDIT RISK

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

	2015				2014				2013
Year Ended December 31, (in millions)	Total Operating Revenues		Percentage of Total Operating Revenues		Total Operating Revenues		Percentage of Total Operating Revenues		Total Operating Revenues		Percentage of Total Operating Revenues
									Predecessor
Columbia Gas of Ohio(1)	$	167.3	12.5	%	$	168.5	12.5	%	$	167.5	14.2	%

(1)Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release 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.

B-50

26.QUARTERLY FINANCIAL DATA (UNAUDITED)

(in millions, except per unit data)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
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
Basic Earnings Per Share
Continuing Operations	0.28			0.16			0.20			0.19
Discontinued Operations	—			—			—			—
Basic Earnings Per Share	$	0.28		$	0.16		$	0.20		$	0.19
Diluted Earnings Per Share
Continuing Operations	0.28			0.16			0.20			0.19
Discontinued Operations	—			—			—			—
Diluted Earnings Per Share	$	0.28		$	0.16		$	0.20		$	0.19
2014
Total Operating Revenues	$	345.8		$	343.5		$	318.0		$	340.7
Operating Income	159.1			103.9			94.5			134.1
Income from Continuing Operations	93.0			59.4			53.7			62.6
Results from Discontinued Operations — net of taxes	(0.2		)	(0.3		)	(0.1		)	—
Net Income attributable to CPG	92.8			59.1			53.6			62.6
Basic Earnings Per Share
Continuing Operations	0.29			0.19			0.17			0.20
Discontinued Operations	—			—			—			—
Basic Earnings Per Share	$	0.29		$	0.19		$	0.17		$	0.20
Diluted Earnings Per Share
Continuing Operations	0.29			0.19			0.17			0.20
Discontinued Operations	—			—			—			—
Diluted Earnings Per Share	$	0.29		$	0.19		$	0.17		$	0.20

27.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.

B-51

COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

27.CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2015 (in millions)	CPG		CEG		OpCo LP		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 and Other Assets
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 and Other Assets	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	25.5		—		—		—		10.6			—			36.1
Total Other Noncurrent Assets	1,892.6		35.6		1,975.5		—		268.8			(1,867.5		)	2,305.0
Total Assets	$	7,894.1	$	7,753.7	$	7,589.7	$	—	$	7,305.2		$	(20,486.5	)	$	10,056.2

B-52

CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)

As of December 31, 2015 (in millions)	CPG			CEG			OpCo LP			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
Non Current Liabilities
Long-term debt	2,746.2			—			—			—		—			—			2,746.2
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	2,761.8			2,586.7			—			—		1,101.4			(1,867.5		)	4,582.4
Total Liabilities	2,881.1			2,591.8			—			—		1,703.5			(2,133.2		)	5,043.2
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	$	7,894.1		$	7,753.7		$	7,589.7		$	—	$	7,305.2		$	(20,486.5	)	$	10,056.2

B-53

CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)

As of December 31, 2014 (in millions)	CPG		CEG		OpCo LP		OpCo GP		Non-guarantor subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	0.5		$	—		$	0.5
Accounts receivable, net	—		—		—		—		149.4			—			149.4
Accounts receivable-affiliated	—		6.2		—		—		174.7			(0.9		)	180.0
Materials and supplies, at average cost	—		—		—		—		24.9			—			24.9
Exchange gas receivable	—		—		—		—		34.8			—			34.8
Deferred property taxes	—		—		—		—		48.9			—			48.9
Deferred income taxes	—		5.9		—		—		54.1			—			60.0
Prepayments and other	—		3.7		—		—		20.8			(3.7		)	20.8
Total Current Assets	—		15.8		—		—		508.1			(4.6		)	519.3
Investments and Other Assets
Unconsolidated affiliates	—		—		—		—		444.3			—			444.3
Consolidated affiliates	4,176.3		4,156.3		—		—		5.7			(8,338.3		)	—
Other investments	—		—		—		—		2.7			—			2.7
Total Investments and Other Assets	4,176.3		4,156.3		—		—		452.7			(8,338.3		)	447.0
Property, Plant and Equipment
Property, plant and equipment	—		—		—		—		7,935.4			—			7,935.4
Accumulated depreciation and amortization	—		—		—		—		(2,976.8		)	—			(2,976.8		)
Net Property, Plant and Equipment	—		—		—		—		4,958.6			—			4,958.6
Other Noncurrent Assets
Regulatory assets	—		—		—		—		151.9			—			151.9
Goodwill	—		—		—		—		1,975.5			—			1,975.5
Postretirement and postemployment benefits assets	—		—		—		—		90.0			—			90.0
Deferred income taxes	—		6.6		—		—		—			(6.6		)	—
Deferred charges and other	—		6.4		—		—		8.8			—			15.2
Total Other Noncurrent Assets	—		13.0		—		—		2,226.2			(6.6		)	2,232.6
Total Assets	$	4,176.3	$	4,185.1	$	—	$	—	$	8,145.6		$	(8,349.5	)	$	8,157.5

B-54

CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)

As of December 31, 2014 (in millions)	CPG			CEG			OpCo LP		OpCo GP		Non-guarantor subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
LIABILITIES AND EQUITY
Current Liabilities
Current portion of long term debt- affiliated	$	—		$	—		$	—	$	—	$	115.9		$	—		$	115.9
Short-term borrowings-affiliated	—			5.2			—		—		247.3			—			252.5
Accounts payable	—			—			—		—		56.0			—			56.0
Accounts payable-affiliated	—			4.4			—		—		50.1			(0.9		)	53.6
Customer deposits	—			—			—		—		13.4			—			13.4
Taxes accrued	—			—			—		—		106.9			(3.7		)	103.2
Exchange gas payable	—			—			—		—		34.7			—			34.7
Deferred revenue	—			—			—		—		22.5			—			22.5
Accrued capital expenditures	—			—			—		—		61.1			—			61.1
Accrued compensation and related costs	—			—			—		—		31.2			—			31.2
Other accruals	—			0.4			—		—		39.7			—			40.1
Total Current Liabilities	—			10.0			—		—		778.8			(4.6		)	784.2
Non Current Liabilities
Long-term debt-affiliated	—			—			—		—		1,472.8			—			1,472.8
Deferred income taxes	—			—			—		—		1,262.3			(6.6		)	1,255.7
Accrued liability for postretirement and postemployment benefits	—			9.3			—		—		43.7			—			53.0
Regulatory liabilities	—			—			—		—		295.7			—			295.7
Asset retirement obligations	—			—			—		—		23.2			—			23.2
Other noncurrent liabilities	—			—			—		—		96.6			—			96.6
Total Noncurrent Liabilities	—			9.3			—		—		3,194.3			(6.6		)	3,197.0
Total Liabilities	—			19.3			—		—		3,973.1			(11.2		)	3,981.2
Equity
Net parent investment	4,210.8			4,195.5			—		—		4,189.2			(8,384.7		)	4,210.8
Accumulated other comprehensive loss	(34.5		)	(29.7		)	—		—		(16.7		)	46.4			(34.5		)
Total Equity	4,176.3			4,165.8			—		—		4,172.5			(8,338.3		)	4,176.3
Total Liabilities and Equity	$	4,176.3		$	4,185.1		$	—	$	—	$	8,145.6		$	(8,349.5	)	$	8,157.5

B-55

COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

27.CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

Year Ended December 31, 2015 (in millions)	CPG			CEG			OpCo LP		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 and impairment, net	—			1.8			—		—		(54.7		)	—			(52.9		)
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

B-56

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Continued)

Year Ended December 31, 2014 (in millions)	CPG			CEG			OpCo LP		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

B-57

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Continued)

Year Ended December 31, 2013 (in millions)	CPG		CEG			OpCo LP		OpCo GP		Non- guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
	Predecessor
Operating Revenues
Transportation revenues	$	—	$	—		$	—	$	—	$	850.9		$	—		$	850.9
Transportation revenues-affiliated	—		—			—		—		94.1			—			94.1
Storage revenues	—		—			—		—		142.8			—			142.8
Storage revenues-affiliated	—		—			—		—		53.6			—			53.6
Other revenues	—		—			—		—		39.1			—			39.1
Total Operating Revenues	—		—			—		—		1,180.5			—			1,180.5
Operating Expenses
Operation and maintenance	—		1.5			—		—		507.5			—			509.0
Operation and maintenance-affiliated	—		0.6			—		—		118.0			—			118.6
Depreciation and amortization	—		—			—		—		107.0			—			107.0
Gain on sale of assets	—		—			—		—		(18.6		)	—			(18.6		)
Property and other taxes	—		—			—		—		62.2			—			62.2
Total Operating Expenses	—		2.1			—		—		776.1			—			778.2
Equity Earnings in Unconsolidated Affiliates	—		—			—		—		35.9			—			35.9
Equity Earnings in Consolidated Affiliates	271.7		266.8			—		—		—			(538.5		)	—
Operating Income	271.7		264.7			—		—		440.3			(538.5		)	438.2
Other Income (Deductions)
Interest expense-affiliated	—		—			—		—		(37.9		)	—			(37.9		)
Other, net	—		0.1			—		—		17.8			—			17.9
Total Other Deductions, net	—		0.1			—		—		(20.1		)	—			(20.0		)
Income from Continuing Operations before Income Taxes	271.7		264.8			—		—		420.2			(538.5		)	418.2
Income Taxes	—		(6.2		)	—		—		152.7			—			146.5
Income from Continuing Operations	271.7		271.0			—		—		267.5			(538.5		)	271.7
Income from Discontinued Operations-net of taxes	9.0		9.0			—		—		—			(9.0		)	9.0
Net Income	$	280.7	$	280.0		$	—	$	—	$	267.5		$	(547.5	)	$	280.7

B-58

COLUMBIA PIPELINE GROUP, INC.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

27.CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2015 (in millions, net of taxes)	CPG			CEG			OpCo LP		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 (loss) gain on cash flow hedges	0.2			(1.6		)	—		—		1.8			(0.2		)	0.2
Unrecognized pension and OPEB benefit (costs)	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			OpCo LP		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 on cash flow hedges	1.0			—			—		—		1.0			(1.0		)	1.0
Unrecognized pension and OPEB costs	(9.7		)	(9.7		)	—		—		—			9.7			(9.7		)
Total other comprehensive (loss) income	(8.7		)	(9.7		)	—		—		1.0			8.7			(8.7		)
Total Comprehensive Income	$	259.4		$	258.4		$	—	$	—	$	270.6		$	(529.0	)	$	259.4
Year Ended December 31, 2013 (in millions, net of taxes)	CPG			CEG			OpCo LP		OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
	Predecessor
Net Income	$	280.7		$	280.0		$	—	$	—	$	267.5		$	(547.5	)	$	280.7
Other comprehensive income
Net unrealized gain on cash flow hedges	1.1			—			—		—		1.1			(1.1		)	1.1
Unrecognized pension and OPEB benefit	8.2			8.2			—		—		—			(8.2		)	8.2
Total other comprehensive income	9.3			8.2			—		—		1.1			(9.3		)	9.3
Total Comprehensive Income	$	290.0		$	288.2		$	—	$	—	$	268.6		$	(556.8	)	$	290.0

B-59

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

Year Ended December 31, 2015 (in millions)	CPG			CEG			OpCo LP			OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
Net Cash Flows (used for) 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 parent	—			—			(500.0		)	—		—			—			(500.0		)
Distribution to parent	(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 parent	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

B-60

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Continued)

Year Ended December 31, 2014 (in millions)	CPG		CEG			OpCo LP		OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
Net Cash Flows (used for) 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 from (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 (used for) 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

Year Ended December 31, 2013 (in millions)	CPG		CEG			OpCo LP		OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
	Predecessor
Net Cash Flows from Operating Activities	$	—	$	162.8		$	—	$	—	$	410.6		$	(116.2	)	$	457.2
Investing Activities
Capital expenditures	—		—			—		—		(674.8		)	—			(674.8		)
Insurance recoveries	—		—			—		—		6.4			—			6.4
Change in short-term lendings-affiliated	—		7.1			—		—		(10.3		)	—			(3.2		)
Proceeds from disposition of assets	—		—			—		—		15.4			—			15.4
Contributions to equity investees	—		—			—		—		(125.5		)	—			(125.5		)
Other investing activities	—		—			—		—		(9.2		)	—			(9.2		)
Net Cash Flows from (used for) Investing Activities	—		7.1			—		—		(798.0		)	—			(790.9		)
Financing Activities
Change in short-term borrowings-affiliated	—		—			—		—		391.0			—			391.0
Issuance of long-term debt-affiliated	—		—			—		—		65.1			—			65.1
Distribution to parent	—		(170.0		)	—		—		(69.2		)	116.2			(123.0		)
Net Cash Flows (used for) from Financing Activities	—		(170.0		)	—		—		386.9			116.2			333.1
Change in cash and cash equivalents	—		(0.1		)	—		—		(0.5		)	—			(0.6		)
Cash and cash equivalents at beginning of period	—		0.1			—		—		0.9			—			1.0
Cash and Cash Equivalents at End of Period	$	—	$	—		$	—	$	—	$	0.4		$	—		$	0.4

B-61

SCHEDULE C

Columbia Pipeline Group, Inc.

Condensed Consolidated Balance Sheets (unaudited)

(in millions)	March 31, 2016			December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	640.9		$	930.9
Accounts receivable (less reserve of $0.3 and $0.6, respectively)	161.5			152.4
Materials and supplies, at average cost	33.2			32.8
Exchange gas receivable	12.0			19.0
Deferred property taxes	54.2			52.0
Prepayments and other	46.5			48.5
Total Current Assets	948.3			1,235.6
Investments
Unconsolidated affiliates	437.3			438.1
Other investments	13.8			13.8
Total Investments	451.1			451.9
Property, Plant and Equipment
Property, plant and equipment	9,426.0			9,052.3
Accumulated depreciation and amortization	(3,025.1		)	(2,988.6		)
Net Property, Plant and Equipment	6,400.9			6,063.7
Other Noncurrent Assets
Regulatory assets	182.2			177.7
Goodwill	1,975.5			1,975.5
Postretirement and postemployment benefits assets	117.7			115.7
Deferred charges and other	15.4			15.5
Total Other Noncurrent Assets	2,290.8			2,284.4
Total Assets	$	10,091.1		$	10,035.6

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

C-1

Columbia Pipeline Group, Inc.

Condensed Consolidated Balance Sheets (unaudited) (continued)

(in millions, except share amounts)	March 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	15.0		$	15.0
Accounts payable	58.7			56.8
Dividends payable	53.6			—
Customer deposits	18.8			17.9
Taxes accrued	101.0			106.0
Interest accrued	37.2			9.5
Exchange gas payable	12.1			18.6
Deferred revenue	10.5			15.0
Accrued capital expenditures	88.7			100.1
Accrued compensation and related costs	28.5			51.9
Other accruals	89.9			70.0
Total Current Liabilities	514.0			460.8
Noncurrent Liabilities
Long-term debt	2,725.9			2,725.6
Deferred income taxes	1,395.3			1,348.1
Accrued liability for postretirement and postemployment benefits	48.9			49.4
Regulatory liabilities	303.6			321.6
Asset retirement obligations	25.1			25.7
Other noncurrent liabilities	94.4			91.4
Total Noncurrent Liabilities	4,593.2			4,561.8
Total Liabilities	5,107.2			5,022.6
Commitments and Contingencies (Refer to Note 17)
Equity
Common stock, $0.01 par value, 2,000,000,000 shares authorized; 400,383,243 and 399,841,350 shares outstanding, respectively	4.0			4.0
Additional paid-in capital	4,037.1			4,032.7
Retained earnings	14.0			46.9
Treasury stock	(6.0		)	—
Accumulated other comprehensive loss	(26.6		)	(27.0		)
Total CPG Equity	4,022.5			4,056.6
Noncontrolling Interest	961.4			956.4
Total Equity	4,983.9			5,013.0
Total Liabilities and Equity	$	10,091.1		$	10,035.6

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

C-2

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated Operations (unaudited)

	Three Months Ended March 31,
(in millions, except per share amounts)	2016			2015
Operating Revenues
Transportation revenues	$	308.5		$	248.4
Transportation revenues-affiliated	—			29.0
Storage revenues	49.9			36.6
Storage revenues-affiliated	—			13.3
Other revenues	6.1			12.7
Total Operating Revenues	364.5			340.0
Operating Expenses
Operation and maintenance	169.1			118.4
Operation and maintenance-affiliated	—			28.0
Depreciation and amortization	40.4			32.5
Gain on sale of assets	(2.6		)	(5.3		)
Property and other taxes	21.8			19.1
Total Operating Expenses	228.7			192.7
Equity Earnings in Unconsolidated Affiliates	15.9			15.4
Operating Income	151.7			162.7
Other Income (Deductions)
Interest expense	(29.4		)	—
Interest expense-affiliated	—			(18.3		)
Other, net	7.0			4.6
Total Other Deductions, net	(22.4		)	(13.7		)
Income from Continuing Operations before Income Taxes	129.3			149.0
Income Taxes	42.7			51.9
Income from Continuing Operations	86.6			97.1
Income from Discontinued Operations-net of taxes	0.2			—
Net Income	86.8			97.1
Less: Net income attributable to noncontrolling interest	14.6			7.1
Net income attributable to CPG	$	72.2		$	90.0
Amounts attributable to CPG:
Income from continuing operations	$	72.0		$	90.0
Income from discontinued operations-net of taxes	0.2			—
Net income attributable to CPG	$	72.2		$	90.0
Basic Earnings Per Share
Continuing operations	$	0.18		$	0.28
Discontinued operations	—			—
Basic Earnings Per Share	$	0.18		$	0.28
Diluted Earnings Per Share
Continuing Operations	$	0.18		$	0.28
Discontinued Operations	—			—
Diluted Earnings Per Share	$	0.18		$	0.28
Basic Average Common Shares Outstanding	400.3			317.6
Diluted Average Common Shares	400.7			317.6
Dividends Declared Per Common Share	$	0.26		$	—

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

C-3

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated Comprehensive Income (unaudited)

	Three Months Ended March 31,
(in millions, net of taxes)	2016		2015
Net Income	$	86.8	$	97.1
Other comprehensive income
Net unrealized gain on cash flow hedges(1)	0.4		0.2
Unrecognized pension and OPEB benefit(2)(3)	0.1		7.0
Total other comprehensive income	0.5		7.2
Total Comprehensive Income	87.3		104.3
Less: Comprehensive Income-noncontrolling interest	14.7		7.1
Comprehensive Income-controlling interests	$	72.6	$	97.2

(1) Net unrealized gains on derivatives qualifying as cash flow hedges, net of $0.2 million and $0.1 million tax expense for the three months ended March 31, 2016 and 2015, respectively.

(2) Unrecognized pension and other postretirement benefit (“OPEB”) benefits, net of $0.1 million and zero tax expense for the three months ended March 31, 2016 and 2015, respectively.

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

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

C-4

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated Cash Flows (unaudited)

Three Months Ended March 31, (in millions)	2016			2015
Operating Activities
Net Income	$	86.8		$	97.1
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
Depreciation and amortization	40.4			32.5
Deferred income taxes and investment tax credits	40.6			36.1
Deferred revenue	(2.0		)	5.3
Equity-based compensation expense and profit sharing contribution	6.2			2.1
Gain on sale of assets	(2.6		)	(5.3		)
Equity earnings in unconsolidated affiliates	(15.9		)	(15.4		)
Income from discontinued operations-net of taxes	(0.2		)	—
Amortization of debt related costs	1.3			—
AFUDC equity	(6.1		)	(3.5		)
Distributions of earnings received from equity investees	18.9			18.3
Changes in Assets and Liabilities:
Accounts receivable	(6.6		)	12.2
Accounts receivable-affiliated	—			15.2
Accounts payable	(4.4		)	(15.6		)
Accounts payable-affiliated	—			(8.6		)
Customer deposits	0.9			0.6
Taxes accrued	(5.0		)	(8.8		)
Interest accrued	27.7			—
Exchange gas receivable/payable	0.5			(0.1		)
Other accruals	(19.3		)	(9.1		)
Prepayments and other current assets	7.1			2.7
Regulatory assets/liabilities	1.5			15.3
Postretirement and postemployment benefits	(0.1		)	(8.7		)
Deferred charges and other noncurrent assets	(2.3		)	(0.2		)
Other noncurrent liabilities	2.6			1.7
Net Operating Activities from Continuing Operations	170.0			163.8
Net Operating Activities from Discontinued Operations	0.3			—
Net Cash Flows from Operating Activities	170.3			163.8
Investing Activities
Capital expenditures	(388.9		)	(163.9		)
Change in short-term lendings-affiliated	—			(698.0		)
Proceeds from disposition of assets	—			10.2
Contributions to equity investees	(1.9		)	—
Distributions from equity investees	0.2			1.3
Other investing activities	(2.0		)	(2.4		)
Net Cash Flows used for Investing Activities	(392.6		)	(852.8		)
Financing Activities
Change in short-term borrowings-affiliated	—			(232.1		)
Debt related costs	(0.5		)	—
Issuance of long-term debt-affiliated	—			1,217.3
Payments of long-term debt-affiliated, including current portion	—			(957.8		)
Proceeds from the issuance of common units, net of offering costs	—			1,168.4
Distribution of IPO proceeds to parent	—			(500.0		)
Distribution to noncontrolling interest	(9.7		)	—
Acquisition of treasury stock	(6.0		)	—
Dividends paid - common stock	(51.5		)	—
Net Cash Flows (used for) from Financing Activities	(67.7		)	695.8
Change in cash and cash equivalents	(290.0		)	6.8
Cash and cash equivalents at beginning of period	930.9			0.5
Cash and Cash Equivalents at End of Period	$	640.9		$	7.3

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

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Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated Equity (unaudited)

(in millions)	Common Stock		Treasury Stock			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance as of January 1, 2016	$	4.0	$	—		$	4,032.7	$	46.9		$	(27.0	)	$	956.4		$	5,013.0
Net Income	—		—			—		72.2			—			14.6			86.8
Other comprehensive income, net of tax	—		—			—		—			0.4			0.1			0.5
Common stock dividends	—		—			—		(105.1		)	—			—			(105.1		)
Treasury stock acquired	—		(6.0		)	—		—			—			—			(6.0		)
Distributions to noncontrolling interest	—		—			—		—			—			(9.7		)	(9.7		)
Long-term incentive plan	—		—			4.4		—			—			—			4.4
Balance as of March 31, 2016	$	4.0	$	(6.0	)	$	4,037.1	$	14.0		$	(26.6	)	$	961.4		$	4,983.9

(in millions)	Net Parent Investment			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance as of January 1, 2015	$	4,210.8		$	(34.5	)	$	—		$	4,176.3
Net Income	90.0			—			7.1			97.1
Other comprehensive income, net of tax	—			7.2			—			7.2
Allocation of AOCI to noncontrolling interest	—			2.2			(2.2		)	—
Issuance of common units of CPPL	—			—			1,168.4			1,168.4
Distribution of IPO proceeds to NiSource	(500.0		)	—			—			(500.0		)
Sale of interest in Columbia OpCo to CPPL(1)	227.1			—			(227.1		)	—
Balance as of March 31, 2015	$	4,027.9		$	(25.1	)	$	946.2		$	4,949.0

(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.

The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.

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Columbia Pipeline Group, Inc.

Notes to Condensed Consolidated Financial Statements (unaudited)

1.    Basis of Accounting Presentation

Columbia Pipeline Group, Inc. (“CPG”) is 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. 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.

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 that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under a tariff 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 is 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. 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 Corp. (“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.

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· 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.

Merger. On March 17, 2016, CPG entered into an Agreement and Plan of Merger (the “Merger Agreement”), among CPG, TransCanada PipeLines Limited, a Canadian corporation (“Parent”), TransCanada PipeLine USA Ltd., a Nevada corporation and a wholly owned subsidiary of Parent (“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 Corporation, a Canadian corporation and the direct parent company of Parent (“TransCanada”). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into CPG (the “Merger”) with CPG surviving the Merger as an indirect wholly owned subsidiary of TransCanada.

The Merger is expected to close in the second half of 2016, subject to satisfaction of customary conditions, including receipt of required regulatory and CPG shareholder approval. Following the completion of the transaction, TransCanada will own 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.

The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although CPG believes that the disclosures made are adequate to make the information not misleading. These financial statements should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2015. These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present CPG’s results of operations and financial position. Amounts reported in the Condensed Statements of Consolidated Operations (unaudited) are not necessarily indicative of amounts expected for the respective annual periods.

CPG’s accompanying Condensed Consolidated Financial Statements (unaudited) have been prepared in accordance with GAAP on the basis of NiSource’s historical ownership of CPG’s assets and its operations. 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, Columbia OpCo and CPG. All intercompany transactions and balances have been eliminated. Also included in the Condensed Consolidated Financial Statements (unaudited) are equity method investments Hardy Storage, Millennium Pipeline and Pennant.

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 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 in CPG’s results. As of March 31, 2016, the portion of CPPL owned by the public is reflected as a noncontrolling interest in the Condensed Consolidated Financial Statements (unaudited).

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

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	Three Months Ended March 31,
(in millions)	2016		2015
Net income attributable to CPG	$	72.2	$	90.0
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	$	72.2	$	317.1

3.    Recent Accounting Pronouncements

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. CPG is required to adopt ASU 2016-09 for periods beginning after December 15, 2016, including interim periods, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2016-09 will have on the Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).

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. As defined in ASU 2016-08, a specified good or service is “a distinct good or service (or a distinct bundle of goods or services) to be provided to the customer.” Therefore, for contracts involving more than one specified good or service, the entity may be the principal for one or more specified goods or services and the agent for others. ASU 2016-08 has the same effective date as ASU 2014-09, as amended by ASU 2015-14. CPG is required to adopt ASU 2016-08 using the same transition method it uses to adopt ASU 2014-09. CPG is currently evaluating the impact the adoption of ASU 2014-09, ASU 2015-14 and ASU 2016-08 will have on the Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).

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 evaluating the impact the adoption of ASU 2016-02 will have on the Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).

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

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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 Condensed Consolidated Balance Sheets (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).

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 Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited).

4.    Earnings Per Share

Basic EPS is based on net income attributable to CPG and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested awards that have not yet been issued as common stock. Diluted EPS includes the above, plus unvested stock awards granted under CPG’s compensation plans, but only to the extent these instruments dilute earnings per share.

On July 1, 2015, 317.6 million shares of CPG common stock were distributed to NiSource stockholders in conjunction with the Separation. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, CPG has assumed this amount to be outstanding as of the beginning of each period prior to the Separation presented in the calculation of weighted average shares outstanding.

The calculation of diluted average common shares is as follows:

	Three Months Ended March 31,
(in millions)	2016	2015
Basic average common shares outstanding	400.3	317.6
Dilutive potential common shares:
Shares restricted under stock plans	0.4	—
Diluted average common shares	400.7	317.6

Dividends. CPG paid a dividend of $0.12875 per share to stockholders on February 19, 2016. On March 22, 2016, CPG declared a dividend of $0.13375 per share to stockholders of record at April 29, 2016, payable May 20, 2016.

5.    Transactions with Affiliates

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 the subsidiaries of NiSource are no longer affiliates. Transactions with affiliates prior to the Separation are summarized below:

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Statement of Operations

	Three Months Ended March 31,
(in millions)	2016		2015
Transportation revenues	$	—	$	29.0
Storage revenues	—		13.3
Other revenues	—		0.1
Operation and maintenance expense	—		28.0
Interest expense	—		18.3
Interest income	—		1.0

Transportation, Storage and Other Revenues. CPG provided natural gas transportation, storage and other services to subsidiaries of NiSource, former affiliates.

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.

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. For the three months ended March 31, 2015, CPG was charged interest for long-term debt of $19.0 million, offset by associated AFUDC of $1.0 million.

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 March 31, 2015 was 1.07%. For the three months ended March 31, 2015, the interest expense for short-term borrowings charged was $0.3 million.

Dividends to NiSource. During the three months ended March 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. There were no restrictions on the payment by CPG of dividends to NiSource.

6.    Short-Term Borrowings

CPG Revolving Credit Facility. On December 5, 2014, CPG entered into a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. The revolving credit facility became effective as of

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the Separation with a termination date of July 2, 2020. CPG expects that $750.0 million of this facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of this facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG’s $1,000.0 million commercial paper program.

Obligations under the CPG revolving credit facility are unsecured. Loans under the CPG revolving credit facility will bear interest at CPG’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent, (b) the reference prime rate of JPMorgan Chase Bank, N.A., or (c) the Eurodollar rate which is based on the LIBOR, plus 1.000 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. CPG’s revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to CPG’s credit rating.

Revolving indebtedness under the CPG credit facility will rank equally with all of CPG’s outstanding unsecured and unsubordinated debt. CEG, OpCo GP and Columbia OpCo have each fully guaranteed the CPG credit facility. The CPG revolving credit facility contains various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo’s partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At March 31, 2016, neither CPG nor its consolidated subsidiaries had any restricted net assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to CPG. The CPG revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million.

The CPG revolving credit facility also contains certain financial covenants that require CPG to maintain a consolidated total leverage ratio that does not exceed (i) 5.50 to 1.00 for any period of four consecutive fiscal quarters (each, a “test period”) ending after December 31, 2015 and on or before December 31, 2017, and (ii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017, and during a Specified Acquisition Period (as defined in the CPG revolving credit facility), the leverage ratio may not exceed 5.50 to 1.00.

A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against CPG or any guarantor.

The Merger, if completed, would constitute a change of control under the terms of the CPG revolving credit facility. Accordingly, in connection with the closing of the Merger, CPG expects the CPG revolving credit facility to be terminated and all outstanding amounts thereunder to be repaid and any existing letters of credit to be replaced. See Note 1, “Basis of Accounting Presentation” for additional information regarding the Merger.

As of March 31, 2016 and December 31, 2015, CPG had no outstanding borrowings and had $18.1 million in letters of credit under the revolving credit facility, respectively.

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CPPL Revolving Credit Facility. On December 5, 2014, CPPL entered into a $500.0 million senior revolving credit facility, of which $50.0 million in letters of credit is available. The revolving credit facility became effective at the closing of CPPL’s IPO with a termination date of February 11, 2020. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls.

CPPL’s obligations under the revolving credit facility are unsecured. The loans thereunder bear interest at CPPL’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the LIBOR, plus 1.000 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. The revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of CPG.

The revolving indebtedness under CPPL’s credit facility ranks equally with all CPPL’s outstanding unsecured and unsubordinated debt. CPG, CEG, OpCo GP and Columbia OpCo have each fully guaranteed CPPL’s credit facility.

CPPL’s revolving credit facility contains various covenants and restrictive provisions which, among other things, limit CPPL’s ability and CPPL’s restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of CPPL’s assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by CPPL’s organizational documents. The restricted payment provision does not prohibit CPPL or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the CPPL revolving credit agreement), and neither CPPL nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. In particular, in accordance with CPPL’s partnership agreement, the general partner has adopted a policy that CPPL will make quarterly cash distributions in amounts equal to at least the minimum quarterly distributions of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. At March 31, 2016, neither CPPL nor its consolidated subsidiaries had any restricted net assets. If CPPL fails to perform the obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. CPPL’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness it may have with an outstanding principal amount in excess of $50.0 million.

The revolving credit facility also contains certain financial covenants that require CPPL to maintain a consolidated total leverage ratio that does not exceed (i) 5.50 to 1.00 for any test period ending after December 31, 2015, and on or before December 31, 2017, and (ii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the CPPL revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00.

A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against CPPL or any guarantor.

The Merger, if completed, would constitute a change of control under the terms of the CPPL revolving credit facility. Accordingly, in connection with the closing of the Merger, CPG expects the CPPL revolving credit facility to be terminated and all outstanding amounts thereunder to be repaid and any existing letters of credit to be replaced. See Note 1, “Basis of Accounting Presentation” for additional information regarding the Merger.

As of March 31, 2016 and December 31, 2015, CPPL had $15.0 million in outstanding borrowings and issued no letters of credit under the revolving credit facility.

CPG Commercial Paper Program. On October 5, 2015, CPG established a commercial paper program (the

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“Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. CEG, OpCo GP and Columbia OpCo have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of March 31, 2016 and December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

Short-term borrowings were as follows:

(in millions)	March 31, 2016		December 31, 2015
Commercial paper borrowings	$	—	$	—
CPG credit facility borrowings	—		—
CPPL credit facility borrowings, weighted average interest rate of 1.50% and 1.28% at March 31, 2016 and December 31, 2015, respectively	15.0		15.0
Total Short-Term Borrowings	$	15.0	$	15.0

Given their maturity and turnover is less than 90 days, cash flows related to the borrowings and repayments of the items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited).

7.    Long-Term Debt

Senior notes issuance. On May 22, 2015, CPG issued its private placement of $2,750.0 million in aggregated principal amount of its 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 Notes were issued at a discount, for net proceeds of approximately $2,722.3 million after deducting the Initial Purchasers’ discount and estimated offering expenses of CPG.

Indenture. The Notes are governed by an Indenture, dated as of May 22, 2015 (the “Indenture”), entered into by CPG and the certain subsidiary guarantors named therein (the “Guarantors”) with U.S. Bank National Association, as trustee (the “Trustee”).

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 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.

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The Indenture governing the Notes 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, commencing on December 1, 2015.

Registration Rights Agreement. In connection with the private placement of the Notes, CPG and the Guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Initial Purchasers, pursuant to which CPG and the Guarantors agreed to file, and use their reasonable best efforts to cause to become effective, an exchange offer registration statement with the SEC and to consummate an exchange offer within 360 days after the date of issuance of the Notes pursuant to which holders of each series of the Notes can exchange the Notes issued in the offering for registered notes having the same terms as the Notes. 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.

8.    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 three months ended March 31, 2016 and 2015, gains on conveyances amounted to $2.6 million and $5.3 million, respectively, and are included in “Gain on sale of assets” on the Condensed Statements of Consolidated Operations (unaudited). As of March 31, 2016 and December 31, 2015, deferred gains of approximately $5.5 million and $8.1 million, respectively, were deferred pending performance of future obligations and recorded within “Deferred revenue,” on the Condensed Consolidated Balance Sheets (unaudited).

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 March 31, 2016 were $1,975.5 million.

CPG’s 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.

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 its reporting unit for the annual impairment test performed as of May 1, 2015. 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 results of this assessment indicated that it is not more likely than not that its reporting unit fair value is less than the reporting unit carrying value.

CPG considered whether there were any events or changes in circumstances subsequent to the annual test that would

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reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. In consideration of all relevant factors, including the recent Merger Agreement, there were no indicators that would require goodwill impairment testing during the first quarter of 2016.

10.    Asset Retirement Obligations

Changes in CPG’s liability for asset retirement obligations for the three months ended March 31, 2016 and 2015 are presented in the table below:

(in millions)	2016			2015
Balance as of January 1,	$	25.7		$	23.2
Accretion expense	0.3			0.3
Additions	—			—
Settlements	—			—
Change in estimated cash flows	(0.9		)	—
Balance as of March 31,	$	25.1		$	23.5

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.

11.    Regulatory Matters

Columbia Gas Transmission Customer Settlement. In November 2015, Columbia Gas Transmission commenced the fourth year of the Columbia Gas Transmission long-term system modernization program. Columbia Gas Transmission expects to place approximately $300 million in modernization investments into service during the year. Recovery of approximately $320 million of investments made in 2015 began on February 1, 2016.

In December 2015, Columbia Gas Transmission filed an extension of this settlement and received the FERC’s approval of the customer agreement in March 2016.This extension will allow Columbia Gas Transmission to invest an additional $1.1 billion over an additional three-year period through 2020. This agreement also expands the scope of facility investments covered by the program.

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. The outcome of this proceeding to Columbia Gulf is not currently determinable.

Cost Recovery Trackers and other similar mechanisms.A significant portion of the transmission and storage regulated companies’ revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under Section 4 of the NGA. However, certain operating costs of the Columbia OpCo regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas. The FERC allows for the recovery of such costs via

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cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system as discussed above.

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 Condensed Consolidated Balance Sheets (unaudited) and CPG’s portion of the results is reflected in “Equity Earnings in Unconsolidated Affiliates” on CPG’s Condensed Statements of Consolidated Operations (unaudited). These investments are integral to CPG’s business. Contributions are made to these equity investees to fund CPG’s share of capital projects.

The following table contains contribution and distribution data representing CPG’s portion based on CPG’s ownership percentage of each investment:

	Three Months Ended March 31,
(in millions)	2016		2015
Millennium Pipeline
Contributions to Millennium Pipeline	$	1.9	$	—
Distributions of earnings from Millennium Pipeline	15.2		16.6
Hardy Storage
Contributions to Hardy Storage	—		—
Distributions of earnings from Hardy Storage	0.7		0.5
Pennant
Contributions to Pennant	—		—
Distributions of earnings from Pennant	3.0		1.2
Return of capital from Pennant	0.2		1.3

13.    Income Taxes

CPG’s interim effective tax rates reflect the estimated annual effective tax rates for 2016 and 2015, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2016 and 2015 were 33.0% and 34.8%, respectively. The effective tax rates for 2016 and 2015 differ from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, other permanent book-to-tax differences and income received following CPPL’s IPO that is not subject to income tax at the partnership level. The effective tax rate is impacted by CPPL’s IPO which modified the ownership structure and now reflects CPPL earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes. CPG consolidates the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but excludes the related tax provision.

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14.    Pension and Other Postretirement Benefits

CPG provides defined contribution plans and noncontributory defined benefit retirement 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 grantor 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 grantor trusts for the plans in which its employees and retirees participated. As a result, CPG followed multiple employer accounting under the provisions of GAAP. CPG continues to follow multiple employer accounting following the Separation.

The following table provides the components of CPG’s net periodic benefits cost for the three months ended March 31, 2016 and 2015:

Three Months Ended March 31, (in	Pension Benefits						Other Postretirement Benefits
millions)	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	1.6		$	1.3		$	0.2		$	0.3
Interest cost	3.9			3.5			1.2			1.2
Expected return on assets	(6.7		)	(7.0		)	(4.0		)	(4.6		)
Amortization of prior service credit	(0.3		)	(0.3		)	(0.2		)	(0.2		)
Recognized actuarial loss	3.1			2.4			—			—
Total Net Periodic Benefit Cost (Income)	$	1.6		$	(0.1	)	$	(2.8	)	$	(3.3	)

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 and short-term borrowings. 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 value of these securities is 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 three months ended March 31, 2016 and for the year ended December 31, 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:

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(in millions)	Carrying Amount as of March 31, 2016(1)		Estimated Fair Value as of March 31, 2016		Carrying Amount as of December 31, 2015(1)		Estimated Fair Value as of December 31, 2015
Long-term debt	$	2,750.0	$	2,732.2	$	2,750.0	$	2,592.1

(1)The carrying amount of the Notes differs from the Long-term debt balance on the Condensed Consolidated Balance Sheets (unaudited) 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.

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 non-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 provides 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. The Omnibus Plan provides that the number of shares of common stock of CPG available for awards is 8,000,000. At March 31, 2016, there were 4,227,203 shares reserved for future awards under the Omnibus Plan.

CPG recognized stock-based employee compensation expense of $3.8 million and $1.8 million during the three months ended March 31, 2016 and 2015, respectively, as well as related tax benefits of $1.4 million and $0.6 million, respectively.

As of March 31, 2016, the total remaining unrecognized compensation cost related to nonvested awards amounted to $33.2 million, which will be amortized over the weighted-average remaining requisite service period of 2.4 years.

Restricted Stock Units and Restricted Stock. During the three months ended March 31, 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. As of March 31, 2016, 1,373,018 nonvested (all of which are expected to vest) restricted stock units and shares of restricted stock were granted and outstanding.

Performance Shares. During the three months ended March 31, 2016, CPG granted 995,848 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. The performance conditions are based on achievement of relative total shareholder return, Adjusted EBITDA and CPPL Distributable Cash Flow. Relative total shareholder return is a non-GAAP market measure that CPG defines as the annualized growth in the dividends and share price of a share of CPG’s common stock (calculated using a 20 trading day average of CPG’s closing price, over a period beginning January 1, 2016 and ending on December 31, 2018) compared to the total shareholder return performance of a predetermined peer group of companies. Adjusted EBITDA is a non-GAAP performance measure that CPG defines as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less equity earnings in unconsolidated affiliates and other, net. In addition, to the extent transactions occur that are considered unusual, infrequent or not representative of underlying trends, we will remove

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the effect of these items from Adjusted EBITDA. Examples of these transactions include impairments, costs associated with the Separation and costs associated with the Merger. CPPL Distributable Cash Flow is a non-GAAP performance measure that CPG defines as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital costs related to the Separation and any other known differences between cash and income. The service conditions lapse on February 28, 2019 when the shares vest provided the performance criteria are satisfied. As of March 31, 2016, 1,117,352 nonvested performance shares were granted and outstanding.

Non-employee Director Awards. Currently, restricted stock units are 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 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 are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. As of March 31, 2016, a total of 52,427 units are outstanding to non-employee directors under the Omnibus Plan. Of these awards, 13,495 were granted under the NiSource Plan and converted into 21,399 CPG units, while the remaining 31,028 were granted by CPG subsequent to the Separation.

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 shall be distributed to the directors upon their separation from CPG’s board of directors or such later date as elected. As of March 31, 2016, 228,619 restricted stock units remain outstanding.

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, 2010, receive a non-elective company contribution of three percent of eligible pay. For the three months ended March 31, 2016 and 2015, CPG recognized 401(k) match, profit sharing and non-elective contribution expense of $3.2 million and $1.7 million, respectively.

17.    Other Commitments and Contingencies

A.    Guarantees and Indemnities. In the normal course of its 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 March 31, 2016 and the years in which they expire were:

(in millions)	Total		2016		2017		2018		2019		2020		After
Letters of credit	$	18.1	$	18.1	$	—	$	—	$	—	$	—	$	—
Other guarantees	45.6		0.6		2.0		—		—		—		43.0
Total commercial commitments	$	63.7	$	18.7	$	2.0	$	—	$	—	$	—	$	43.0

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. CPG does not anticipate its subsidiaries will have any difficulty maintaining compliance.

Lines and Letters of Credit. CPG maintains a $1,500.0 million senior revolving credit facility, of which $250.0

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million in letters of credit is available. CPG expects that $750.0 million of this facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of this facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG’s $1,000.0 million commercial paper program. As of March 31, 2016, CPG had no borrowings outstanding and $18.1 million in letters of credit outstanding under its revolving credit facility. CPPL maintains a $500.0 million senior revolving credit facility, of which $50.0 million is available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures, and the funding of capital calls. As of March 31, 2016, CPPL had $15.0 million in outstanding borrowings and no letters of credit under its revolving credit facility.

CPG has established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. CEG, OpCo GP and Columbia OpCo have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of March 31, 2016, CPG had no Promissory Notes outstanding under the Program.

Other Guarantees or Obligations. CPG has purchase and sale agreement guarantees totaling $45.6 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 Condensed Consolidated Balance Sheets (unaudited). 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.

CPG has on deposit a letter of credit with MUFG Union Bank, N.A., Collateral Agent, in a debt service reserve account in association with Millennium Pipeline’s notes as required under the Deposit and Disbursement Agreement that governs the Millennium Pipeline notes. This account is to be drawn upon by the note holders in the event that Millennium Pipeline is delinquent on its principal and interest payments. The value of CPG’s letter of credit represents 47.5% (CPG’s ownership interest in Millennium Pipeline) of the debt service reserve account requirement, or $16.2 million. The total exposure for CPG is $16.2 million. CPG has an accrued liability of $1.5 million related to the inception date fair value of this guarantee as of March 31, 2016.

B.    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 condensed consolidated financial statements.

C.    Environmental Matters. CPG’s operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. CPG believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary material permits to conduct its operations.

It is 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 March 31, 2016 and December 31, 2015, CPG had liabilities recorded of approximately $8.2 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 Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in “Other noncurrent liabilities” in the Condensed Consolidated Balance Sheets (unaudited). 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

C-21

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.

The following NAAQS were recently added or modified:

Ozone: On October 1, 2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 ppb under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is required to include an adequate margin of safety in establishing the primary ozone standard for protection of public health, whereas the secondary ozone standard is intended to improve protection for trees, plants and ecosystems. The final rule becomes effective sixty days after the rule is published in the Federal Register. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With the EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations. Based on the current version of the rule, CPG does not expect a material impact on its operations.

Nitrogen Dioxide (NO2): The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing CPG combustion sources may need to be assessed and mitigated. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

Climate Change. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.

New Source Performance Standards: On August 18, 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. Semiannual leak detection and repair requirements using optical gas imaging are proposed for all components at new or existing compressor stations. Existing compressor stations trigger leak detection and repair requirements if any unit at the facility is modified. The EPA proposed additional requirements for any new or modified centrifugal or reciprocating compressors. Replacement of wet seals with dry seals or demonstrating a 95% reduction of methane emissions from wet seals is proposed for centrifugal compressors and rod packing replacement for reciprocating compressors is proposed every 26,000 hours of operation or every three years. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

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Pipeline Safety

On March 17, 2016, the federal Pipeline and Hazardous Materials Safety Administration (“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. Adoption of some or all of these standards under the proposed rulemaking could cause us to incur increased capital costs and costs of operation, which could be significant.

Waste

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 $6.4 million and $6.5 million at March 31, 2016 and December 31, 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 $1.8 million at March 31, 2016 and December 31, 2015. The liability represents CPG’s best estimate of the cost to remediate the facilities.

18.    Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss for the three months ended March 31, 2016 and 2015:

Three Months Ended March 31, 2016 (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, 2016	$	(14.3	)	$	(12.7	)	$	(27.0	)
Other comprehensive income before reclassifications	—			0.1			0.1
Amounts reclassified from accumulated other comprehensive income	0.4			—			0.4
Net current-period other comprehensive income	0.4			0.1			0.5
Allocation of accumulated other comprehensive loss to noncontrolling interest	0.1			—			0.1
Balance as of March 31, 2016	$	(14.0	)	$	(12.6	)	$	(26.6	)

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

C-23

Three Months Ended March 31, 2015 (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, 2015	$	(16.6	)	$	(17.9	)	$	(34.5	)
Other comprehensive income before reclassifications	—			6.9			6.9
Amounts reclassified from accumulated other comprehensive income	0.2			0.1			0.3
Net current-period other comprehensive income	0.2			7.0			7.2
Allocation of accumulated other comprehensive loss to noncontrolling interest	2.2			—			2.2
Balance as of March 31, 2015	$	(14.2	)	$	(10.9	)	$	(25.1	)

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

Equity Investment

Millennium Pipeline is an equity method investment, and, therefore, CPG is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss at March 31, 2016 of $14.0 million, after tax, related to 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 $14.0 million and $14.3 million, after tax, at March 31, 2016 and December 31, 2015, respectively, is included in gains and losses on cash flow hedges above.

19.    Other, Net

	Three Months Ended March 31,
(in millions)	2016		2015
AFUDC Equity	$	6.1	$	3.5
Miscellaneous	0.9		1.1
Total Other, net	$	7.0	$	4.6

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20.    Supplemental Cash Flow Information

The following table provides additional information regarding CPG’s Condensed Statements of Consolidated Cash Flows (unaudited) for the three months ended March 31, 2016 and 2015:

(in millions)	2016		2015
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities(1)	$	120.7	$	98.8
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	6.2	$	15.6
Cash paid for income taxes	1.1		9.4

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

21.    Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for greater than 10% of total operating revenues for the three months ended March 31, 2016 and 2015. The following tables provide this customer’s operating revenues and percentage of total operating revenues for the three months ended March 31, 2016 and 2015:

Three Months Ended March 31,	2016				2015
(in millions)	Total Operating Revenues		Percentage of Total Operating Revenues		Total Operating Revenues		Percentage of Total Operating Revenues
Columbia Gas of Ohio(1)	$	50.4	13.8	%	$	48.9	14.4	%

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

The loss of a significant portion of operating revenues from this customer could have a material adverse effect on the business of CPG.

22.    Condensed Consolidating Financial Information

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 7, “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.

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CONDENSED CONSOLIDATING BALANCE SHEETS

As of March 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	$	549.2	$	53.8	$	—	$	—	$	37.9		$	—		$	640.9
Accounts receivable, net	0.5		5.6		—		—		155.4			—			161.5
Accounts receivable-affiliated	105.4		193.4		—		—		135.5			(434.3		)	—
Materials and supplies, at average cost	—		—		—		—		33.2			—			33.2
Exchange gas receivable	—		—		—		—		12.0			—			12.0
Deferred property taxes	—		—		—		—		54.2			—			54.2
Prepayments and other	9.3		4.6		—		—		41.9			(9.3		)	46.5
Total Current Assets	664.4		257.4		—		—		470.1			(443.6		)	948.3
Investments
Unconsolidated affiliates	—		—		—		—		437.3			—			437.3
Consolidated affiliates	5,278.9		7,624.1		5,791.0		—		—			(18,694.0		)	—
Other investments	12.0		0.3		—		—		1.5			—			13.8
Total Investments	5,290.9		7,624.4		5,791.0		—		438.8			(18,694.0		)	451.1
Property, Plant and Equipment
Property, plant and equipment	—		—		—		—		9,426.0			—			9,426.0
Accumulated depreciation and amortization	—		—		—		—		(3,025.1		)	—			(3,025.1		)
Net Property, Plant and Equipment	—		—		—		—		6,400.9			—			6,400.9
Other Noncurrent Assets
Regulatory assets	—		41.1		—		—		141.1			—			182.2
Goodwill	—		—		1,975.5		—		—			—			1,975.5
Notes receivable-affiliated	1,848.2		—		—		—		—			(1,848.2		)	—
Postretirement and postemployment benefits assets	—		0.6		—		—		117.5			(0.4		)	117.7
Deferred income taxes	23.3		—		—		—		—			(23.3		)	—
Deferred charges and other	4.6		—		—		—		10.8			—			15.4
Total Other Noncurrent Assets	1,876.1		41.7		1,975.5		—		269.4			(1,871.9		)	2,290.8
Total Assets	$	7,831.4	$	7,923.5	$	7,766.5	$	—	$	7,579.2		$	(21,009.5	)	$	10,091.1

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CONDENSED CONSOLIDATING BALANCE SHEETS (continued)

As of March 31, 2016 (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	—			—			124.0			—		283.9			(407.9		)	—
Accounts payable	11.0			—			—			—		47.7			—			58.7
Accounts payable-affiliated	7.8			14.9			0.1			—		3.6			(26.4		)	—
Dividends payable	53.6			—			—			—		—			—			53.6
Customer deposits	—			—			—			—		18.8			—			18.8
Taxes accrued	—			10.6			—			—		99.7			(9.3		)	101.0
Interest accrued	37.0			—			—			—		0.2			—			37.2
Exchange gas payable	—			—			—			—		12.1			—			12.1
Deferred revenue	—			—			—			—		10.5			—			10.5
Accrued capital expenditures	—			—			—			—		88.7			—			88.7
Accrued compensation and related costs	—			—			—			—		28.5			—			28.5
Other accruals	0.3			0.3			—			—		89.3			—			89.9
Total Current Liabilities	109.7			25.8			124.1			—		698.0			(443.6		)	514.0
Noncurrent Liabilities
Long-term debt	2,725.9			—			—			—		—			—			2,725.9
Long-term debt-affiliated	—			1,217.3			—			—		630.9			(1,848.2		)	—
Deferred income taxes	—			1,396.7			—			—		21.9			(23.3		)	1,395.3
Accrued liability for postretirement and postemployment benefits	0.3			7.8			—			—		41.2			(0.4		)	48.9
Regulatory liabilities	—			10.4			—			—		293.2			—			303.6
Asset retirement obligations	—			—			—			—		25.1			—			25.1
Other noncurrent liabilities	11.6			0.3			—			—		82.5			—			94.4
Total Noncurrent Liabilities	2,737.8			2,632.5			—			—		1,094.8			(1,871.9		)	4,593.2
Total Liabilities	2,847.5			2,658.3			124.1			—		1,792.8			(2,315.5		)	5,107.2
Equity
Common stock	4.0			—			—			—		—			—			4.0
Additional paid-in capital	4,037.1			—			—			—		—			—			4,037.1
Retained earnings	14.0			—			—			—		—			—			14.0
Net parent investment	—			4,330.2			7,667.3			—		5,815.4			(17,812.9		)	—
Treasury stock	(6.0		)	—			—			—		—			—			(6.0		)
Accumulated other comprehensive loss	(26.6		)	(26.4		)	(24.9		)	—		(29.0		)	80.3			(26.6		)
Total CPG Equity	4,022.5			4,303.8			7,642.4			—		5,786.4			(17,732.6		)	4,022.5
Noncontrolling Interest	961.4			961.4			—			—		—			(961.4		)	961.4
Total Equity	4,983.9			5,265.2			7,642.4			—		5,786.4			(18,694.0		)	4,983.9
Total Liabilities and Equity	$	7,831.4		$	7,923.5		$	7,766.5		$	—	$	7,579.2		$	(21,009.5	)	$	10,091.1

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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

C-29

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

Three Months Ended March 31, 2016  (in millions)	CPG			CEG			Columbia OpCo			OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
Operating Revenues
Transportation revenues	$	—		$	—		$	—		$	—	$	308.5		$	—		$	308.5
Transportation revenues-affiliated	—			—			—			—		—			—			—
Storage revenues	—			—			—			—		49.9			—			49.9
Storage revenues-affiliated	—			—			—			—		—			—			—
Other revenues	—			—			—			—		6.1			—			6.1
Total Operating Revenues	—			—			—			—		364.5			—			364.5
Operating Expenses
Operation and maintenance	30.4			(0.2		)	—			—		139.1			(0.2		)	169.1
Operation and maintenance-affiliated	0.1			—			—			—		—			(0.1		)	—
Depreciation and amortization	—			0.2			—			—		40.2			—			40.4
Gain on sale of assets	—			—			—			—		(2.6		)	—			(2.6		)
Property and other taxes	0.1			—			—			—		21.7			—			21.8
Total Operating Expenses	30.6			—			—			—		198.4			(0.3		)	228.7
Equity Earnings in Unconsolidated Affiliates	—			—			—			—		15.9			—			15.9
Equity Earnings in Consolidated Affiliates	113.5			179.8			181.5			—		—			(474.8		)	—
Operating Income	82.9			179.8			181.5			—		182.0			(474.5		)	151.7
Other Income (Deductions)
Interest expense	(29.5		)	—			—			—		(0.6		)	0.7			(29.4		)
Interest expense-affiliated	—			(11.2		)	(0.1		)	—		(7.2		)	18.5			—
Other, net	19.7			0.5			—			—		6.0			(19.2		)	7.0
Total Other Deductions, net	(9.8		)	(10.7		)	(0.1		)	—		(1.8		)	—			(22.4		)
Income from Continuing Operations before Income Taxes	73.1			169.1			181.4			—		180.2			(474.5		)	129.3
Income Taxes	(13.5		)	56.8			—			—		0.5			(1.1		)	42.7
Income from Continuing Operations	86.6			112.3			181.4			—		179.7			(473.4		)	86.6
Income from Discontinued Operations-net of taxes	0.2			0.2			—			—		—			(0.2		)	0.2
Net Income	86.8			112.5			181.4			—		179.7			(473.6		)	86.8
Less: Net income attributable to noncontrolling interest	14.6			14.6			—			—		—			(14.6		)	14.6
Net Income Attributable to CPG	$	72.2		$	97.9		$	181.4		$	—	$	179.7		$	(459.0	)	$	72.2

C-30

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (continued)

Three Months Ended March 31, 2015  (in millions)	CPG		CEG			Columbia OpCo		OpCo GP		Non-guarantor Subsidiaries			Consolidating adjustments and eliminations			CPG Consolidated
Operating Revenues
Transportation revenues	$	—	$	—		$	—	$	—	$	248.4		$	—		$	248.4
Transportation revenues-affiliated	—		—			—		—		29.0			—			29.0
Storage revenues	—		—			—		—		36.6			—			36.6
Storage revenues-affiliated	—		—			—		—		13.3			—			13.3
Other revenues	—		—			—		—		12.7			—			12.7
Total Operating Revenues	—		—			—		—		340.0			—			340.0
Operating Expenses
Operation and maintenance	—		(0.1		)	—		—		118.5			—			118.4
Operation and maintenance-affiliated	—		0.1			—		—		27.9			—			28.0
Depreciation and amortization	—		—			—		—		32.5			—			32.5
Gain on sale of assets	—		—			—		—		(5.3		)	—			(5.3		)
Property and other taxes	—		—			—		—		19.1			—			19.1
Total Operating Expenses	—		—			—		—		192.7			—			192.7
Equity Earnings in Unconsolidated Affiliates	—		—			—		—		15.4			—			15.4
Equity Earnings in Consolidated Affiliates	97.1		131.2			131.2		—		—			(359.5		)	—
Operating Income	97.1		131.2			131.2		—		162.7			(359.5		)	162.7
Other Income (Deductions)
Interest expense-affiliated	—		(6.9		)	—		—		(11.4		)	—			(18.3		)
Other, net	—		0.4			0.7		—		3.5			—			4.6
Total Other Deductions, net	—		(6.5		)	0.7		—		(7.9		)	—			(13.7		)
Income before Income Taxes	97.1		124.7			131.9		—		154.8			(359.5		)	149.0
Income Taxes	—		27.6			—		—		24.3			—			51.9
Net Income	97.1		97.1			131.9		—		130.5			(359.5		)	97.1
Less: Net income attributable to noncontrolling interest	7.1		7.1			—		—		—			(7.1		)	7.1
Net Income Attributable to CPG	$	90.0	$	90.0		$	131.9	$	—	$	130.5		$	(352.4	)	$	90.0

C-31

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended March 31, 2016  (in millions, net of taxes)	CPG		CEG			Columbia OpCo		OpCo GP		Non-guarantor Subsidiaries		Consolidating adjustments and eliminations			CPG Consolidated
Net Income	$	86.8	$	112.5		$	181.4	$	—	$	179.7	$	(473.6	)	$	86.8
Other comprehensive income
Net unrealized gain on cash flow hedges	0.4		(0.1		)	—		—		0.5		(0.4		)	0.4
Unrecognized pension and OPEB benefit	0.1		0.1			—		—		—		(0.1		)	0.1
Total other comprehensive income	0.5		—			—		—		0.5		(0.5		)	0.5
Total Comprehensive Income	87.3		112.5			181.4		—		180.2		(474.1		)	87.3
Less: Comprehensive Income-noncontrolling interest	14.7		14.7			—		—		—		(14.7		)	14.7
Comprehensive Income-controlling interests	$	72.6	$	97.8		$	181.4	$	—	$	180.2	$	(459.4	)	$	72.6

Three Months Ended March 31, 2015  (in millions, net of taxes)	CPG		CEG			Columbia OpCo		OpCo GP		Non-guarantor Subsidiaries		Consolidating adjustments and eliminations			CPG Consolidated
Net Income	$	97.1	$	97.1		$	131.9	$	—	$	130.5	$	(359.5	)	$	97.1
Other comprehensive income
Net unrealized gain on cash flow hedges	0.2		(0.1		)	—		—		0.3		(0.2		)	0.2
Unrecognized pension and OPEB benefit	7.0		7.0			—		—		—		(7.0		)	7.0
Total other comprehensive income	7.2		6.9			—		—		0.3		(7.2		)	7.2
Total Comprehensive Income	104.3		104.0			131.9		—		130.8		(366.7		)	104.3
Less: Comprehensive Income-noncontrolling interest	7.1		7.1			—		—		—		(7.1		)	7.1
Comprehensive Income-controlling interests	$	97.2	$	96.9		$	131.9	$	—	$	130.8	$	(359.6	)	$	97.2

C-32

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

Three Months Ended March 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	$	(6.7	)	$	116.4		$	—		$	—	$	198.2		$	(137.6	)	$	170.3
Investing Activities
Capital expenditures	—			—			—			—		(388.9		)	—			(388.9		)
Change in short-term lendings-affiliated	(87.1		)	(109.3		)	3.3			—		18.6			174.5			—
Contributions to equity investees	—			—			—			—		(1.9		)	—			(1.9		)
Distributions from equity investees	—			—			—			—		0.2			—			0.2
Other investing activities	—			—			—			—		(2.0		)	—			(2.0		)
Net Cash Flows used for Investing Activities	(87.1		)	(109.3		)	3.3			—		(374.0		)	174.5			(392.6		)
Financing Activities
Change in short-term borrowings-affiliated	(99.0		)	—			124.0			—		149.5			(174.5		)	—
Debt related costs	(0.5		)	—			—			—		—			—			(0.5		)
Quarterly distributions to unitholders	—			—			—			—		(18.1		)	18.1			—
Distribution to noncontrolling interest in Columbia OpCo	—			—			(129.2		)	—		—			129.2			—
Distribution to noncontrolling interest	—			—			—			—		—			(9.7		)	(9.7		)
Acquisition of treasury stock	(6.0		)	—			—			—		—			—			(6.0		)
Dividends paid - common stock	(51.5		)	—			—			—		—			—			(51.5		)
Net Cash Flows used for Financing Activities	(157.0		)	—			(5.2		)	—		131.4			(36.9		)	(67.7		)
Change in cash and cash equivalents	(250.8		)	7.1			(1.9		)	—		(44.4		)	—			(290.0		)
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	$	549.2		$	53.8		$	—		$	—	$	37.9		$	—		$	640.9

C-33

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (continued)

Three Months Ended March 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	$	(4.6	)	$	(3.9	)	$	0.3		$	—	$	172.0		$	—		$	163.8
Investing Activities
Capital expenditures	—			—			—			—		(163.9		)	—			(163.9		)
Change in short-term lendings-affiliated	—			—			(668.1		)	—		(29.9		)	—			(698.0		)
Proceeds from disposition of assets	—			—			—			—		10.2			—			10.2
Contributions to equity investees	—			(1,217.3		)	—			—		—			1,217.3			—
Distributions from equity investees	—			—			—			—		1.3			—			1.3
Other investing activities	—			—			—			—		(2.4		)	—			(2.4		)
Net Cash Flows used for Investing Activities	—			(1,217.3		)	(668.1		)	—		(184.7		)	1,217.3			(852.8		)
Financing Activities
Change in short-term borrowings-affiliated	4.6			3.9			—			—		(240.6		)	—			(232.1		)
Issuance of long-term debt-affiliated	—			1,217.3			—			—		—			—			1,217.3
Payments of long-term debt-affiliated, including current portion	—			—			—			—		(957.8		)	—			(957.8		)
Proceeds from the issuance of common units, net of offering costs	—			—			1,170.0			—		(1.6		)	—			1,168.4
Contribution of capital from parent	—			—			—			—		1,217.3			(1,217.3		)	—
Distribution of IPO proceeds to parent	—			—			(500.0		)	—		—			—			(500.0		)
Net Cash Flows from Financing Activities	4.6			1,221.2			670.0			—		17.3			(1,217.3		)	695.8
Change in cash and cash equivalents	—			—			2.2			—		4.6			—			6.8
Cash and cash equivalents at beginning of period	—			—			—			—		0.5			—			0.5
Cash and Cash Equivalents at End of Period	$	—		$	—		$	2.2		$	—	$	5.1		$	—		$	7.3

C-34

SCHEDULE D

TransCanada Corporation

Unaudited Pro Forma Condensed Consolidated Financial Statements

As at and for the three months ended March 31, 2016 and

for the year ended December 31, 2015

D-1

Unaudited Pro Forma Condensed Consolidated Financial Statements

The following unaudited pro forma condensed consolidated financial statements give effect to the transaction between TransCanada PipeLines Limited (“TCPL”), TransCanada PipeLine USA Ltd. (“TransCanada Holdco”) and Taurus Merger Sub Inc. (“Merger Sub”), all direct or indirect wholly-owned subsidiaries of TransCanada Corporation (“TransCanada” or the “Corporation”), and Columbia Pipeline Group, Inc. (“Columbia”) using the acquisition method of accounting. On March 17, 2016, TCPL, TransCanada Holdco, Merger Sub and the Corporation (for the limited purposes of pursuing regulatory approvals and obtaining the financing for the Acquisition and providing representations and warranties), entered into an agreement and plan of merger (the “Merger Agreement”) with Columbia, pursuant to which TCPL, indirectly through TransCanada Holdco and Merger Sub, agreed to acquire Columbia through a merger of Merger Sub with and into Columbia (the “Acquisition”) for a purchase price of approximately $13.4 billion (US$10.3 billion) in cash, as described in the Business Acquisition Report dated July 20, 2016 (the “BAR”). The Acquisition was completed July 1, 2016, and Columbia is an indirect wholly-owned subsidiary of TransCanada.

The unaudited pro forma condensed consolidated financial statements have been derived from, and should be read in conjunction with, the historical December 31, 2015 audited consolidated financial statements of the Corporation and Columbia and notes thereto; the March 31, 2016 condensed consolidated financial statements of the Corporation and Columbia and notes thereto; and the accompanying notes to the unaudited pro forma condensed consolidated financial statements. The unaudited pro forma condensed consolidated balance sheet data as at March 31, 2016 of the Corporation has been prepared to give effect to the Acquisition as if it had occurred on March 31, 2016. The unaudited pro forma condensed consolidated statements of income of the Corporation, for the year ended December 31, 2015 and for the three months ended March 31, 2016, have been prepared to give effect to the Acquisition as if it occurred on January 1, 2015. The unaudited pro forma condensed consolidated financial statements include pro forma adjustments for which there are firm commitments and for which the complete financial effects are objectively determinable as well as adjustments to conform Columbia’s financial statement amounts to the Corporation’s accounting policies.

The unaudited pro forma condensed consolidated statements of income for the year ended December 31, 2015 and for the three months ended March 31, 2016 include adjustments that are expected to have a continuing impact on the condensed consolidated results but exclude adjustments arising from non-recurring effects of the transaction that are not expected to continue in future periods. The unaudited pro forma condensed consolidated balance sheet as at March 31, 2016 includes adjustments that are directly attributable to the transaction and factually supportable, regardless of whether they have continuing effect or are non-recurring. The unaudited pro forma condensed consolidated financial statements do not give effect to any cost savings, operating synergies, and revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The unaudited pro forma condensed consolidated financial statements exclude the impact of permanent financing through the planned monetization of the Corporation’s U.S. Northeast merchant power assets and of a minority interest in its Mexican natural gas pipeline business.

The pro forma adjustments are based on available preliminary information and certain assumptions that management of the Corporation believes are reasonable under the circumstances. The unaudited pro forma condensed consolidated financial statements are presented for informational purposes only.

D-2

Future results may vary significantly from the results reflected because of various factors, including those discussed in the Corporation’s 2015 Management’s Discussion and Analysis and Consolidated Financial Statements as at December 31, 2015 and December 31, 2014, and for each of the years in the three-year period ended December 31, 2015 as well as the Corporation’s Management’s Discussion and Analysis and Condensed Consolidated Financial Statements as at and for the three months ended March 31, 2016. All pro forma adjustments and their underlying assumptions are described more fully in the notes to the unaudited pro forma condensed consolidated financial statements.

D-3

TransCanada Corporation

Unaudited Pro Forma Condensed Consolidated Statement of Income

For the year ended December 31, 2015

(Unaudited) year ended December 31, 2015	TCC		Columbia		Columbia		Pro Forma Adjustments		Notes	Pro Forma Statement of Income
(millions of Canadian $, unless otherwise noted)			US$		Note 3i
Revenues
Natural Gas Pipelines	5,383		1,335		1,707					7,090
Liquids Pipelines	1,879		—		—					1,879
Energy	4,038		—		—					4,038
	11,300		1,335		1,707		—		Note 3j	13,007
Income from Equity Investments	440		61		78					518
Operating and Other Expenses
Plant operating costs and other	3,250		705		902					4,152
Commodity purchases resold	2,237		—		—					2,237
Property taxes	517		75		96					613
Depreciation and amortization	1,765		140		179		13		Note 3b	1,957
Asset impairment charges	3,745		—		—					3,745
	11,514		920		1,177		13			12,704
(Loss)/Gain on Assets Held for Sale/Sold	(125	)	53		68					(57	)
Financial Charges
Interest expense	1,370		97		124		(29	)	Note 3b
							158		Note 3d	1,623
Interest income and other	(163	)	(29	)	(37	)				(200	)
	1,207		68		87		129			1,423
(Loss)/Income before Income Taxes	(1,106	)	461		589		(142	)		(659	)
Income Tax Expense/(Recovery)
Current	136		21		27					163
Deferred	(102	)	132		169		(62	)	Note 3d
							(5	)	Note 3b
							11		Note 3b	11
	34		153		196		(56	)		174
Net (Loss)/Income from Continued Operations	(1,140	)	308		393		(86	)		(833	)
Net (Loss)/Income from Discontinued Operations	—		(1	)	(1	)				(1	)
Net (Loss)/Income	(1,140	)	307		392		(86	)		(834	)
Net Income attributable to non-controlling interests	6		40		51					57
Net (Loss)/Income Attributable to Controlling Interests	(1,146	)	267		341		(86	)		(891	)
Preferred share dividends	94		—		—					94
Net (Loss)/Income Attributable to Common Shares	(1,240	)	267		341		(86	)		(985	)
Net (Loss)/Income per Common Share
Basic and diluted	(1.75	)							Note 3h	(1.22	)
Weighted Average Number of Common Shares (millions)
Basic	709						97		Note 3h	806
Diluted	709						97		Note 3h	806

D-4

TransCanada Corporation

Unaudited Pro Forma Condensed Consolidated Statement of Income

For the three months ended March 31, 2016

(Unaudited) three months ended March 31, 2016	TCC		Columbia		Columbia		Pro Forma Adjustments		Notes	Pro Forma Statement of Income
(millions of Canadian $, unless otherwise noted)			US$		Note 3i
Revenues
Natural Gas Pipelines	1,313		364		491					1,804
Liquids Pipelines	480		—		—					480
Energy	754		—		—					754
	2,547		364		491		—		Note 3j	3,038
Income from Equity Investments	135		16		22					157
Operating and Other Expenses
Plant operating costs and other	715		169		228					943
Commodity purchases resold	514		—		—					514
Property taxes	141		22		30					171
Depreciation and amortization	454		40		54		3		Note 3b	511
Asset impairment charges	211		—		—					211
	2,035		231		312		3			2,350
(Loss)/Gain on Assets Held for Sale/Sold	(4	)	3		4					—
Financial Charges
Interest expense	420		29		39		(7	)	Note 3b
							42		Note 3d	494
Interest income and other	(201	)	(7	)	(9	)				(210	)
	219		22		30		35			284
Income/(Loss) before Income Taxes	424		130		175		(38	)		561
Income Tax Expense/(Recovery)
Current	34		2		3					37
Deferred	36		41		55		(16	)	Note 3d
							(1	)	Note 3b
							3		Note 3b	77
	70		43		58		(14	)		114
Net Income/(Loss) from Continued Operations	354		87		117		(24	)		447
Net Income/(Loss) from Discontinued Operations	—		—		—					—
Net Income/(Loss)	354		87		117		(24	)		447
Net Income attributable to non-controlling interests	80		15		20					100
Net Income/(Loss) Attributable to Controlling Interests	274		72		97		(24	)		347
Preferred share dividends	22		—		—					22
Net Income/(Loss) Attributable to Common Shares	252		72		97		(24	)		325
Net Income/(Loss) per Common Share
Basic and diluted	0.36								Note 3h	0.41
Weighted Average Number of Common Shares (millions)
Basic	702						97		Note 3h	799
Diluted	703						97		Note 3h	800

D-5

TransCanada Corporation

Unaudited Pro Forma Condensed Consolidated Balance Sheet

As at March 31, 2016

(Unaudited) at March 31, 2016	TCC		Columbia		Columbia		Pro Forma Adjustments		Notes	Pro Forma Balance Sheet
(millions of Canadian $, unless otherwise noted)			US$		Note 3i
ASSETS
Current Assets
Cash and cash equivalents	1,238		641		831		(13,352	)	Note 3b
							4,419		Note 3c
							9,023		Note 3d
							(144	)	Note 3c
							(54	)	Note 3d
							(36	)	Note 3e	1,925
Accounts receivable	1,381		162		210		—			1,591
Inventories	356		33		43		—			399
Other	1,162		112		145		—			1,307
	4,137		948		1,229		(144	)		5,222
Plant, Property and Equipment	44,461		6,401		8,302		324		Note 3b
							836		Note 3b
							(14	)	Note 3b	53,909
Equity Investments	6,275		451		585		—			6,860
Regulatory Assets	1,160		182		236		—			1,396
Goodwill	4,510		1,976		2,563		(2,563	)	Note 3b
							10,078		Note 3b	14,588
Intangible and Other Assets	3,012		133		173		15		Note 3d
							39		Note 3c	3,239
Restricted Investments	403		—		—		—			403
	63,958		10,091		13,088		8,571.00			85,617
LIABILITIES
Current Liabilities
Notes payable	2,270		—		—		—			2,270
Accounts payable and other	2,875		477		619		155		Note 3b	3,649
Accrued interest	463		37		48		—			511
Current portion of long-term debt	1,529		—		—		—			1,529
	7,137		514		667		155			7,959
Regulatory Liabilities	1,447		304		394		—			1,841
Other Long-Term Liabilities	1,270		168		218		—			1,488
Deferred Income Tax Liabilities	5,031		1,395		1,809		126		Note 3b
							326		Note 3b
							(5	)	Note 3b
							(117	)	Note 3b
							(60	)	Note 3b	7,110
Long-Term Debt	28,980		2,726		3,536		300		Note 3b
							9,023		Note 3d
										41,839
Junior Subordinated Notes	2,257		—		—		—			2,257
	46,122		5,107		6,624		9,748			62,494
EQUITY
Common Shares, no par value	12,099		4		5		(5	)	Note 3g
							4,419		Note 3c	16,518
Preferred Shares	2,499		—		—					2,499
Additional Paid-in Capital	—		4,037		5,236		(5,236	)	Note 3g	—
Retained Earnings	2,594		9		12		(12	)	Note 3g
							(105	)	Note 3c
							(39	)	Note 3d
							(36	)	Note 3e	2,414
Accumulated Other Comprehensive Loss	(999	)	(27	)	(35	)	35		Note 3g	(999	)
Controlling Interests	16,193		4,023		5,218		(979	)		20,432
Non-controlling Interests	1,643		961		1,246		(198	)	Note 3b	2,691
Total Equity	17,836		4,984		6,464		(1,177	)		23,123
	63,958		10,091		13,088		8,571			85,617

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Notes to Unaudited Pro forma Condensed Consolidated Financial Statements

As at and for the three months ended March 31, 2016 and

for the year ended December 31, 2015

(millions of Canadian dollars, unless otherwise noted)

1. BASIS OF PRESENTATION

The accompanying unaudited pro forma condensed consolidated financial statements give effect to the Acquisition. The unaudited pro forma condensed consolidated financial statements have been prepared by management of the Corporation and are derived from the unaudited and audited consolidated financial statements of the Corporation as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively, as well as the unaudited and audited consolidated financial statements of Columbia as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively.

The unaudited pro forma condensed consolidated financial statements utilize accounting policies that are consistent with those used in the Corporation’s March 31, 2016 unaudited financial statements and were prepared in accordance with United States generally accepted accounting principles (U.S. GAAP). Amounts are stated in Canadian dollars (“dollars” or “$”) unless otherwise indicated. References to “U.S. dollars” and “US$” are to lawful currency of the U.S.

The Acquisition has been accounted for using the acquisition method. The purchase price for Columbia was approximately $13.4 billion in cash (Note 3a).

The unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statements of income reflect the Acquisition as if it had closed on March 31, 2016   and January 1, 2015, respectively.  The accompanying unaudited pro forma condensed consolidated financial statements may not be indicative of the results that would have been achieved if the transactions reflected therein had been completed on the dates indicated or the results which may be obtained in the future. For instance, the actual purchase price equation will reflect the fair value, at the July 1, 2016 purchase date, of the assets acquired and liabilities assumed based upon the Corporation’s evaluation of such assets and liabilities following the closing of the Acquisition. Accordingly, the final purchase price equation, as it relates principally to goodwill, may differ materially from the preliminary purchase price equation reflected herein.

The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the description of the Acquisition and the financing thereof provided in the BAR; the historical December 31, 2015 audited consolidated financial statements of the Corporation and Columbia and notes thereto; and the March 31, 2016 condensed consolidated financial statements of the Corporation and Columbia and notes thereto. The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effect directly attributable to the Acquisition. These pro forma adjustments are tentative and are based on currently available financial information and certain estimates and assumptions. The actual adjustments to the consolidated financial statements

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will depend on a number of factors. Therefore, it is expected that the actual adjustments will differ from the pro forma adjustments, and the differences may be material.

2. DESCRIPTION OF TRANSACTION

Pursuant to the Merger Agreement, TCPL, indirectly through TransCanada Holdco and Merger Sub, acquired Columbia on July 1, 2016 through a merger of Merger Sub with and into Columbia. The purchase price of $13.4 billion (US$10.3 billion) (Note 3a) is based on US$25.50 per share for all of Columbia’s outstanding common shares as well as restricted and performance stock units. The purchase price excludes estimated acquisition costs of $36 million. The unaudited pro forma condensed consolidated financial statements reflect that the Acquisition was financed through (i) net proceeds from the sale of the Subscription Receipts (Note 3c), (ii) amounts drawn under the Acquisition Credit Facilities (Note 3d) and (iii) existing cash on hand. The sale of the Subscription Receipts, which were exchangeable to common shares, totaling $4.4 billion (Note 3c) was completed on April 1, 2016 through a public offering as described above. TCPL also arranged committed debt bridge facilities underwritten by certain financial institutions in the aggregate amount of $9.0 billion (US$6.9 billion) (Note 3d). The Acquisition was completed July 1, 2016, and Columbia is an indirect wholly-owned subsidiary of TransCanada.

3. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

a)Purchase price and financing structure

The following is the purchase price, funding requirements and financing structure utilized for the Acquisition, in Canadian dollars. These amounts have been reflected in the accompanying unaudited pro forma condensed consolidated financial statements.

Purchase Price
Purchase price	Note 3b	13,352
Funding Requirements
Purchase price		13,352
Subscription Receipt issuance costs	Note 3c	144
Acquisition Credit Facilities’ costs	Note 3d	54
Acquisition costs	Note 3e	36
Funding requirements		13,586
Financing Structure
Subscription Receipts	Note 3c	4,419
Acquisition Credit Facilities	Note 3d	9,023
Cash on hand		144
Total		13,586

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b)Estimated purchase price equation

The estimated purchase price equation is comprised of the estimated fair values of Columbia net assets and liabilities as at March 31, 2016 in accordance with the acquisition method, as follows:

(millions of Canadian $, unless otherwise noted)	Columbia	Columbia	Fair Value and Other Adjustments		Fair Value
	US$	Note 3i
Assets Acquired
Cash and cash equivalents	641	831	—		831
Accounts receivable	162	210	—		210
Inventories	33	43	—		43
Other	112	145	—		145
Total Current Assets	948	1,229	—		1,229
Plant, Property and Equipment	6,401	8,302	1,146		9,448
Equity Investments	451	585	—		585
Regulatory Assets	182	236	—		236
Goodwill	1,976	2,563	(2,563	)	—
Intangible and Other Assets	133	173			173
Total Assets	10,091	13,088	(1,417	)	11,671
Liabilities Assumed
Accounts payable and other	477	619	155		774
Accrued interest	37	48	—		48
Total Current Liabilities	514	667	155		822
Regulatory Liabilities	304	394	—		394
Other Long-Term Liabilities	168	218	—		218
Deferred Income Tax Liabilities	1,395	1,809	270		2,079
Long-Term Debt	2,726	3,536	300		3,836
Total Liabilities	5,107	6,624	725		7,349
Non-controlling Interests	961	1,246	(198	)	1,048
Net Assets	4,023	5,218	(1,944	)	3,274
Purchase Price					13,352
Goodwill					10,078

Under the acquisition method, the acquired tangible and intangible assets and assumed liabilities of the acquired entity are primarily measured at their estimated fair value at the date of acquisition. The excess of the fair value of the consideration transferred over the preliminary estimated fair value of net assets acquired is classified as goodwill on the accompanying unaudited pro forma condensed consolidated balance sheet. Such goodwill is not amortized but will be evaluated for impairment on, at least, an annual basis.  The estimated fair values and useful lives of assets acquired and liabilities assumed are based on preliminary management estimates and are subject to final valuation adjustments which may cause some of the amounts ultimately recorded as goodwill to be materially different from those shown on the unaudited pro forma condensed consolidated balance sheet. The preliminary estimates used to prepare the pro forma information presented will be updated based upon management’s final analysis.

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The fair values of cash and cash equivalents, accounts receivable, inventories, other current assets and accrued interest approximate their carrying values due to their short-term nature. However, certain working capital adjustments are expected resulting in an increase in the fair value of accounts payable and other of $155 million. This increase in fair value would result in a corresponding deferred income tax asset of approximately $60 million at March 31, 2016 based on the Corporation’s U.S. statutory income tax rate of 39%.

The fair value of mineral rights included in Columbia’s plant, property and equipment was estimated using a third party valuation report resulting in a higher fair value over the book value at March 31, 2016. The difference of $324 million between the fair value and the book value of the mineral rights will be amortized into income over their estimated useful lives, resulting in an estimated depreciation expense of $13 million ($8 million after-tax) and $3 million ($2 million after-tax) for the year ended December 31, 2015 and for the three months ended March 31, 2016, respectively. This increase in fair value would result in a corresponding deferred income tax liability of approximately $126 million at March 31, 2016 based on TransCanada’s U.S. statutory income tax rate of 39%.

The fair value of base gas included in Columbia’s plant, property and equipment was estimated using market prices resulting in a higher fair value over the book value at March 31, 2016. The difference of $836 million between the fair value and the book value of the base gas will not be amortized into income. This increase in fair value would result in a corresponding deferred income tax liability of approximately $326 million at March 31, 2016 based on TransCanada’s U.S. statutory income tax rate of 39%.

The fair value of software under development included in Columbia’s plant, property and equipment was estimated to be nil based on management’s assumption that this software will no longer continue to be developed. As a result, plant, property and equipment was reduced by $14 million resulting in a corresponding deferred income tax asset of approximately $5 million at March 31, 2016 based on TransCanada’s U.S. statutory income tax rate of 39%.

The fair value of Columbia’s long-term debt was estimated using an income approach based on quoted market prices for similar debt instruments from external data service providers. This resulted in a higher fair value over the carrying value at March 31, 2016. The difference of $300 million between the fair value and carrying value will be amortized into income as a reduction of interest expense over the term of the long-term debt resulting in an estimated reduction of interest expense of $29 million ($18 million after-tax) and $7 million ($4 million after-tax) for the year ended December 31, 2015 and for the three months ended March 31, 2016, respectively. This increase in fair value would result in a corresponding deferred income tax asset of approximately $117 million at March 31, 2016 based on TransCanada’s U.S. statutory income tax rate of 39%.

The fair value of Columbia’s non-controlling interests is based on the approximately 53.8 million Columbia Pipeline Partners LP (“Columbia MLP”) common units outstanding to the public as of March 31, 2016, and valued at Columbia MLP’s June 30, 2016 closing price of US$15.00 per common unit.

D-10

c)Subscription receipts

Financing for the Acquisition used proceeds from the sale of approximately 97 million Subscription Receipts for gross proceeds of approximately $4.4 billion. Each Subscription Receipt entitled the holder thereof to automatically receive, upon the closing of the Acquisition and without any further action on the part of the holder thereof and without payment of additional consideration, one common share of the Corporation. Underwriting costs were approximately $144 million ($105 million after-tax) and will result in a corresponding deferred income tax asset of approximately $39 million based on TransCanada’s Canadian statutory income tax rate of 27%.

d)Acquisition credit facilities

The closing of the Acquisition was partially financed by a drawdown of bridge debt facilities underwritten by various financial institutions in an aggregate principal amount of $9.0 billion (US$6.9 billion) (the “Acquisition Credit Facilities”). The Acquisition Credit Facilities are intended to be repaid through the planned monetization of the Corporation’s U.S. Northeast merchant power assets and of a minority interest in its Mexican natural gas pipeline business. The impact of this repayment is not included in the unaudited condensed consolidated pro forma financial statements.

Acquisition Credit Facilities’ costs are approximately $54 million ($39 million after-tax) and have been included as a pro forma adjustment to retained earnings on the unaudited pro forma condensed consolidated balance sheet but are not being reflected in the unaudited pro forma condensed consolidated statement of income. These costs also result in a corresponding deferred income tax asset of approximately $15 million at March 31, 2016 based on TransCanada’s Canadian statutory income tax rate of 27%.

The interest rate is 1.6% on the Acquisition Credit Facilities, which would result in incremental interest expense of $158 million and $42 million for the year ended December 31, 2015 and for the three months ended March 31, 2016, respectively. Incremental interest expense would result in a corresponding deferred income tax recovery of approximately $62 million and $16 million for the year ended December 31, 2015 and for the three months ended March 31, 2016, respectively based on TransCanada’s U.S. statutory income tax rate of 39%.

e)Acquisition costs

Acquisition costs are estimated at approximately $36 million. Acquisition costs are composed of estimated investment banking, accounting, tax, legal and other costs associated with the completion of the Acquisition. These costs have been included as a pro forma adjustment to retained earnings on the unaudited pro forma condensed consolidated balance sheet as opposed to being reflected in the unaudited pro forma condensed consolidated statement of income on the basis that these expenses are directly incremental to the acquisition of Columbia and are non-recurring in nature.

f)Income taxes

For the purpose of the accompanying unaudited pro forma condensed consolidated financial statements including pro forma adjustments, average Canadian and U.S. deferred income tax rates of 26% and 39%, respectively, have been applied for the year ended December 31, 2015 and 27% and 39%, respectively, for the three months ended March 31, 2016. The deferred income tax asset and liability is the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities. Deferred income tax assets and liabilities are measured at the tax rates expected to apply when these differences reverse.

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g)Columbia historical shareholders’ equity

The historical shareholders’ equity of Columbia, which includes common shares, additional paid-in capital, retained earnings and accumulated other comprehensive income has been eliminated.

h)Earnings per common share

Earnings per common share is calculated by dividing net (loss)/income attributable to common shares by the weighted average number of common shares outstanding for the year. The calculation of the pro forma earnings per common share for the year ended December 31, 2015 and the three months ended March 31, 2016 reflects the issuance of approximately 97 million of TransCanada common shares, as if the issuance had taken place on January 1, 2015. The basic and diluted weighted average number of common shares outstanding in 2015 was 709 million. The basic and diluted weighted average number of common shares outstanding in first quarter 2016 was 702 million and 703 million, respectively. This resulted in a basic and diluted pro forma loss per common share of $1.22 for the year ended December 31, 2015 and a basic and diluted pro forma earnings per common share of $0.41 for the three months ended March 31, 2016.

i)Foreign exchange translation

The assets and liabilities of Columbia, which has a US dollar reporting and functional currency, are translated at the exchange rate in effect as at the unaudited pro forma condensed consolidated balance sheet date of March 31, 2016. Revenues and expenses of Columbia’s operations are translated at the average exchange rate in effect during the reporting periods. The following exchange rates were utilized for the unaudited pro forma condensed consolidated financial statements:

Balance Sheet (US dollars to Canadian dollars)

Closing rate – March 31, 2016: 1.297

Income Statement (US dollars to Canadian dollars)

Average rate – January 1, 2015 to December 31, 2015: 1.279

Average rate – January 1, 2016 to March 31, 2016: 1.348

j)Segment classification

For the purpose of the accompanying unaudited pro forma condensed consolidated statement of income, Columbia’s transportation, storage and other revenues have been combined with the Corporation’s Natural Gas Pipeline revenues. As certain Columbia revenues may be different in nature from the Corporation’s Natural Gas Pipeline revenues, following the closing of the Acquisition and based upon management’s final analysis, segment classification may vary from the assumption made to prepare the unaudited pro forma condensed consolidated statements of income.

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