EX-99.1 2 a16-15341_1ex99d1.htm EX-99.1

Exhibit 99.1

 

FORM 51-102F4
BUSINESS ACQUISITION REPORT

 

ITEM 1 IDENTITY OF COMPANY

 

1.1                               Name and Address of Company

 

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

 

1.2                               Executive Officer

 

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

 

ITEM 2 DETAILS OF ACQUISITION

 

2.1                               Nature 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.

 

2.2                               Acquisition Date

 

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

 

2.3                               Consideration

 

On July 1, 2016, TCPL 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 Corporation (“TransCanada”), parent company of TCPL, 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, TransCanada 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 TransCanada through existing cash on hand.

 

2.4                               Effect on Financial Position

 

Except as described below, TCPL 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 TCPL.

 

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. TransCanada does not anticipate any asset dropdowns to the MLPs until the review has been completed.

 

2.5                               Prior Valuations

 

To the knowledge of the Corporation, there has not been any valuation opinion obtained within the last twelve months by Columbia or TCPL 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.

 



 

2.6                               Parties to Transaction

 

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

 

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

 

2.7                               Date 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 TCPL 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, the issuance by the Corporation of common shares to TransCanada and an intercompany loan due to TransCanada in connection with proceeds received by the Corporation from the issuance of common shares of TransCanada 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. 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.

 

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. 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 PipeLines Limited

 



 

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.

 

B-2



 

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.

 

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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’

 

B-12



 

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:

 

B-13



 

(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:

 

B-14



 

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

 

B-15



 

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

 

B-16



 

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

 

B-17



 

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

 

B-18



 

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”),

 

B-19



 

$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

 

B-25



 

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.

 

B-26



 

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.

 

B-28



 

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.