Results of Operations
The following schedule presents our historical consolidated key operating and financial metrics.
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|
|
|
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Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Operating Revenues
|
|
|
|
|
|
Transportation revenues
|
$
|
1,155.1
|
|
|
$
|
1,054.4
|
|
|
$
|
990.8
|
|
Transportation revenues-affiliated
|
—
|
|
|
47.5
|
|
|
95.7
|
|
Storage revenues
|
196.5
|
|
|
171.4
|
|
|
144.0
|
|
Storage revenues-affiliated
|
—
|
|
|
26.2
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|
|
53.2
|
|
Other revenues
|
30.4
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|
|
35.4
|
|
|
64.3
|
|
Total Operating Revenues
|
1,382.0
|
|
|
1,334.9
|
|
|
1,348.0
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Operating Expenses
|
|
|
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Operation and maintenance
|
863.2
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|
652.1
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|
628.4
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Operation and maintenance-affiliated
|
—
|
|
|
52.9
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|
|
123.2
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Depreciation and amortization
|
172.8
|
|
|
139.9
|
|
|
118.8
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Gain on sale of assets
|
(16.6
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)
|
|
(55.3
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)
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|
(34.5
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)
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Impairment of long-lived assets
|
26.1
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2.4
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|
|
—
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Property and other taxes
|
83.2
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|
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75.3
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|
|
67.1
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|
Total Operating Expenses
|
1,128.7
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|
|
867.3
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|
|
903.0
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|
Equity Earnings in Unconsolidated Affiliates
|
64.3
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|
|
60.5
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|
|
46.6
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Operating Income
|
317.6
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|
|
528.1
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|
|
491.6
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Other Income (Deductions)
|
|
|
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Interest expense
|
(119.1
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)
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(67.6
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)
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|
—
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Interest expense-affiliated
|
(2.1
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)
|
|
(29.3
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)
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|
(62.0
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)
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Other, net
|
35.1
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|
|
29.3
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|
|
8.8
|
|
Total Other Deductions, net
|
(86.1
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)
|
|
(67.6
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)
|
|
(53.2
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)
|
Income from Continuing Operations before Income Taxes
|
231.5
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|
|
460.5
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|
438.4
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Income Taxes
|
77.8
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|
153.0
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|
169.7
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Income from Continuing Operations
|
153.7
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|
|
307.5
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|
|
268.7
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Income (Loss) from Discontinued Operations-net of taxes
|
0.2
|
|
|
(0.4
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)
|
|
(0.6
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)
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Net Income
|
153.9
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|
|
307.1
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|
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$
|
268.1
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Less: Net income attributable to noncontrolling interest
|
37.1
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|
|
39.9
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|
Net income attributable to CPG
|
$
|
116.8
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|
|
$
|
267.2
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|
|
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Throughput (MMDth)
|
|
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|
Columbia Gas Transmission
|
1,759.5
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|
|
1,460.1
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|
|
1,379.4
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|
Columbia Gulf
|
552.2
|
|
|
562.7
|
|
|
626.7
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Crossroads
|
15.5
|
|
|
15.5
|
|
|
16.7
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Total
|
2,327.2
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|
|
2,038.3
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|
|
2,022.8
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Year Ended
December 31, 2016
Compared to Year Ended
December 31, 2015
Operating Revenues
. Operating revenues were
$1,382.0 million
for
2016
, an
increase
of
$47.1 million
from the same period in
2015
. The
increase
in operating revenues was primarily due to increased demand revenue of $108.3 million largely from the East Side Expansion, Broad Run Connector and Rayne XPress growth projects, and the CCRM. Additionally, there were increased shorter term transportation services of $5.0 million and higher commodity revenue of $3.7 million. These increases were partially offset by a decrease of $66.6 million attributable to the recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense, and lower mineral rights royalty revenue of $4.6 million.
Columbia Pipeline Group, Inc.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Operating Expenses
. Operating expenses were
$1,128.7 million
for
2016
, an
increase
of
$261.4 million
from the same period in
2015
. The
increase
in operating expenses was primarily due to higher costs related to the Merger of $174.8 million, increased costs related to the Separation of $56.0 million, decreased gains on the sale of assets of $38.7 million, primarily due to conveyances of mineral interests, higher depreciation and amortization of $32.9 million and increased property and other taxes of $6.3 million, both primarily due to higher levels of in-service assets. Additionally, there were higher impairment charges of $23.7 million due to the cancellation of IT system upgrades and increased maintenance expenses of $6.9 million. These variances were partially offset by $66.6 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and lower employee and administrative costs of $11.3 million.
Equity Earnings in Unconsolidated Affiliates
. Equity Earnings in Unconsolidated Affiliates were
$64.3 million
in
2016
, an
increase
of
$3.8 million
compared to the same period in
2015
. Equity earnings increased primarily due to earnings generated by Millennium Pipeline and Pennant.
Other Income (Deductions)
. Other income (deductions) in
2016
reduced
income by
$86.1 million
compared to a
reduction
in income of
$67.6 million
in
2015
. The variance was primarily due to an increase in interest expense of $12.5 million and higher amortization of debt related costs of $1.2 million, both resulting from the issuance of long-term debt in May 2015, as well as $5.7 million of accelerated amortization of deferred costs associated with the CPG and CPPL revolving credit facilities that were terminated early. Additionally, there was higher expense of $4.1 million in the debt portion of AFUDC. These increased deductions were partially offset by an increase in other income of $6.6 million for the equity portion of AFUDC.
Income Taxes
. The effective income tax rates were comparable at
33.6%
and
33.2%
in
2016
and
2015
, respectively.
Throughput
. Throughput totaled
2,327.2
MMDth for
2016
, compared to
2,038.3
MMDth for the same period in
2015
. The
increase
of
288.9
MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.
Year Ended
December 31, 2015
Compared to Year Ended
December 31, 2014
Operating Revenues
. Operating revenues were
$1,334.9 million
for
2015
, a
decrease
of
$13.1 million
from the same period in
2014
. The
decrease
in operating revenues was primarily due to a decrease of $112.4 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in operating expenses, decreased mineral rights royalty revenue of $17.6 million, lower condensate revenues of $4.5 million, decreased revenue from the settlement of gas imbalances of $4.0 million and lower commodity revenue of $2.3 million. These decreases were partially offset by increased demand revenue of $126.8 million primarily from the CCRM, the West Side Expansion growth project and other new contracts. Additionally, there were higher shorter term transportation services of $3.5 million.
Operating Expenses
. Operating expenses were
$867.3 million
for
2015
, a
decrease
of
$35.7 million
from the same period in
2014
. The
decrease
in operating expenses was primarily due to $112.4 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and increased gains on the conveyances of mineral interests of $17.8 million. These variances were partially offset by higher employee and administrative expenses of $24.4 million due to higher employee costs, increased depreciation of $21.1 million primarily due to increased capital expenditures related to projects placed in service, $18.8 million in Separation costs, higher outside service costs of $15.0 million and increased property and other taxes of $8.2 million.
Equity Earnings in Unconsolidated Affiliates
. Equity Earnings in Unconsolidated Affiliates were
$60.5 million
in
2015
, an
increase
of
$13.9 million
compared to the same period in
2014
. Equity earnings increased primarily due to the Pennant joint venture going fully in-service and new compression assets being placed into service at Millennium Pipeline.
Other Income (Deductions)
. Other income (deductions) in
2015
reduced
income by
$67.6 million
compared to a
reduction
in income of
$53.2 million
in
2014
. The increased expense was primarily due to an increase of $36.1 million in interest expense. This was a result of increased interest of $67.5 million related to the May 2015 issuance of $2.75 billion of long-term debt at CPG, offset by lower affiliated interest of $30.6 million with NiSource Finance due to the repayment of long-term debt-affiliated. Additionally, this increase in interest expense was partially offset by an increase of $17.3 million in the equity portion of AFUDC and an increase in the debt portion of AFUDC of $6.7 million.
Income Taxes
. The effective income tax rates were
33.2%
and
38.7%
in
2015
and
2014
, respectively. The change in the overall effective tax rates between
2015
and
2014
was primarily due to income before income tax attributable to noncontrolling interest
Columbia Pipeline Group, Inc.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
following CPPL’s IPO that is not subject to an income tax provision, as well as the effects of tax credits, state income taxes, utility rate-making and other permanent book-to-tax differences
Throughput
. Throughput totaled
2,038.3
MMDth for
2015
, compared to
2,022.8
MMDth for the same period in
2014
. The
increase
of
15.5
MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.
Other Information
Critical Accounting Policies
We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on the CPG’s results of operations and Consolidated Balance Sheets.
Basis of Accounting for Rate-Regulated Subsidiaries.
ASC Topic 980,
Regulated Operations
, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were
$176.9 million
and
$293.4 million
at
December 31, 2016
, and
$182.7 million
and
$322.8 million
at
December 31, 2015
, respectively. For additional information, refer to Note 11, “Regulatory Matters,” in the Notes to Consolidated and Combined Financial Statements.
In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980,
Regulated Operations
. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply the provisions of ASC Topic 980,
Regulated Operations
, we would be required to apply the provisions of ASC Topic 980-20,
Discontinuation of Rate-Regulated Accounting
. In management’s opinion, our regulated companies will be subject to ASC Topic 980,
Regulated Operations
for the foreseeable future.
No
regulatory assets are earning a return on investment at
December 31, 2016
. Regulatory assets of
$58.9 million
are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to
6
years.
Pensions and Postretirement Benefits.
CPG has defined benefit plans for both pensions and other postretirement benefits that cover its employees. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of CPG’s pensions and other postretirement benefits, please see Note 14, “Pension and Other Postretirement Benefits,” in the audited Notes to Consolidated and Combined Financial Statements.
Goodwill.
In accordance with the provisions for goodwill accounting under GAAP, we test our goodwill for impairment annually as of May 1 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB. Columbia Gas Transmission Operations is a component and has been determined to be a reporting unit. Our goodwill assets at
December 31, 2016
and
December 31, 2015
were
$1,975.5 million
pertaining to NiSource's acquisition of CEG on November 1, 2000.
The Predecessor completed a quantitative (“step 1”) fair value measurement of our reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed under the step 1 annual impairment test. For 2015 and 2016, a qualitative (“step 0”) test was performed as of May 1 of each respective period. We assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit in its baseline May 1, 2012 test. The results of these assessments indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value and no impairments is necessary.
Although there was no goodwill asset impairment as of May 1, 2016, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase
Columbia Pipeline Group, Inc.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
in the discount rate or changes in other key assumptions which require judgment and are forward looking in nature. In consideration of all relevant factors, there were no indicators that would require goodwill impairment testing subsequent to May 1, 2016.
Please see Notes 1-I and 9, “Goodwill” in the Notes to Consolidated and Combined Financial Statements for further discussion.
Revenue Recognition.
Revenue is recognized as services are performed. For regulated entities, revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for services provided but not billed.
The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues for both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.
CPG provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided.
Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
CPG includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was
$21.5 million
,
$26.5 million
and
$43.8 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, and are included in “Other revenues” on the Statements of Consolidated and Combined Operations.
We periodically recognize gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if CPG has a substantial obligation for future performance. As the obligation for future performance is satisfied, the deferred revenue is relieved and the associated gain is recognized. Gains on the conveyance of mineral interest amounted to
$16.9 million
,
$52.3 million
and
$34.5 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, and are included in “Gain on sale of assets” on the Statements of Consolidated and Combined Operations.
Recently Issued Accounting Pronouncements
Refer to Note 3, "Recent Accounting Pronouncements," in the Notes to Consolidated and Combined Financial Statements.
Columbia Pipeline Group, Inc.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk is an inherent part of our business
. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to its profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal risks that are involved in our businesses: credit risk, interest rate risk and commodity market risk. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These include but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of our business, our risk management processes, policies and procedures continue to evolve and are subject to ongoing review and modification.
Commodity Price Risk
. Other than the base gas purchased and used in the natural gas storage facilities, which is necessary to maintain pressure and deliverability in the storage pools, we generally do not take title to the natural gas that we store and/or transport for customers and, accordingly, we are not exposed to commodity price fluctuations on natural gas stored in our facilities or transported through our pipelines by our customers. Base gas purchased and used in natural gas storage facilities is considered a long-term asset and is not re-valued at current market prices. A certain amount of gas is naturally lost in connection with transporting natural gas across our pipeline system and, under our contractual arrangements with our customers, we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as our fuel usage. Except for the base gas in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to the volumes of fuel we purchase to make up for line loss, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas over the intermediate term should not materially impact our operations. We have not historically engaged in material commodity hedging activities relating to our assets. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.
Interest Rate Risk
. We have exposure to interest rate risk as a result of changes in interest rates that are indexed to short-term market interest rates on borrowings under our revolving credit facilities and former commercial paper program. Based upon average borrowings, an increase or decrease in interest rates of 100 basis points (1%) would have resulted in increased or decreased interest expense of $2.2 million and $2.1 million for the years ended
December 31, 2016
and 2015, respectively. We monitor market debt rates to identify the need to mitigate this risk.
Credit Risk
. Due to the nature of the industry, credit risk is embedded in our business activities. Our extension of credit is governed by TransCanada’s policies relating to credit risk, which include guidelines for documenting management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by TransCanada’s corporate credit risk function which is independent of operations. Credit risk arises due to the possibility that a customer will not be able or willing to fulfill its obligations on a transaction on or before the settlement date.
Columbia Pipeline Group, Inc.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Columbia Pipeline Group, Inc.
Houston, Texas
We have audited the accompanying financial statements of Columbia Pipeline Group, Inc. (the "Company") (a wholly owned subsidiary of TransCanada Corporation), which comprise the consolidated balance sheets as of December 31, 2016 and 2015, the related statements of consolidated and combined operations, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present fairly, in all material respects, the financial position of Columbia Pipeline Group, Inc. and subsidiaries at as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, on July 1, 2015 the Company completed its spin-off from NiSource Inc. and on July 1, 2016, TransCanada Corporation completed its acquisition of the Company. As discussed in Note 2 to the consolidated financial statements, on February 11, 2015, the Company completed the initial public offering of limited partner interests of Columbia Pipeline Partners LP for net proceeds of $1,168.4 million.
/s/ DELOITTE & TOUCHE LLP
Columbus, Ohio
February 17, 2017
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
(in millions)
|
December 31, 2016
|
|
December 31, 2015
|
ASSETS
|
|
|
|
Current Assets
|
|
|
|
Cash and cash equivalents
|
$
|
79.9
|
|
|
$
|
930.9
|
|
Accounts receivable (less reserve of $0.3 and $0.6, respectively)
|
194.2
|
|
|
152.4
|
|
Accounts receivable-affiliated
|
55.8
|
|
|
—
|
|
Materials and supplies, at average cost
|
26.0
|
|
|
32.8
|
|
Exchange gas receivable
|
27.7
|
|
|
19.0
|
|
Deferred property taxes
|
61.2
|
|
|
52.0
|
|
Prepayments and other
|
28.9
|
|
|
48.5
|
|
Total Current Assets
|
473.7
|
|
|
1,235.6
|
|
Investments
|
|
|
|
Unconsolidated affiliates
|
446.7
|
|
|
438.1
|
|
Other investments
|
0.8
|
|
|
13.8
|
|
Total Investments
|
447.5
|
|
|
451.9
|
|
Property, Plant and Equipment
|
|
|
|
Property, plant and equipment
|
10,461.2
|
|
|
9,052.3
|
|
Accumulated depreciation and amortization
|
(3,126.2
|
)
|
|
(2,988.6
|
)
|
Net Property, Plant and Equipment
|
7,335.0
|
|
|
6,063.7
|
|
Other Noncurrent Assets
|
|
|
|
Regulatory assets
|
172.9
|
|
|
177.7
|
|
Goodwill
|
1,975.5
|
|
|
1,975.5
|
|
Postretirement and postemployment benefits assets
|
121.8
|
|
|
115.7
|
|
Deferred charges and other
|
11.3
|
|
|
15.5
|
|
Total Other Noncurrent Assets
|
2,281.5
|
|
|
2,284.4
|
|
Total Assets
|
$
|
10,537.7
|
|
|
$
|
10,035.6
|
|
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
(in millions, except share amounts)
|
December 31, 2016
|
|
December 31, 2015
|
LIABILITIES, TEMPORARY EQUITY AND EQUITY
|
|
|
|
Current Liabilities
|
|
|
|
Short-term borrowings
|
$
|
—
|
|
|
$
|
15.0
|
|
Accounts payable
|
70.4
|
|
|
56.8
|
|
Accounts payable-affiliated
|
4.0
|
|
|
—
|
|
Customer deposits
|
17.3
|
|
|
17.9
|
|
Taxes accrued
|
116.9
|
|
|
106.0
|
|
Interest accrued
|
9.4
|
|
|
9.5
|
|
Exchange gas payable
|
27.2
|
|
|
18.6
|
|
Deferred revenue
|
3.9
|
|
|
15.0
|
|
Accrued capital expenditures
|
111.4
|
|
|
100.1
|
|
Accrued compensation and related costs
|
62.3
|
|
|
51.9
|
|
Other accruals
|
110.1
|
|
|
70.0
|
|
Total Current Liabilities
|
532.9
|
|
|
460.8
|
|
Noncurrent Liabilities
|
|
|
|
Long-term debt
|
2,728.6
|
|
|
2,725.6
|
|
Deferred income taxes
|
1,500.4
|
|
|
1,348.1
|
|
Accrued liability for postretirement and postemployment benefits
|
32.2
|
|
|
49.4
|
|
Regulatory liabilities
|
273.6
|
|
|
321.6
|
|
Asset retirement obligations
|
20.8
|
|
|
25.7
|
|
Other noncurrent liabilities
|
59.8
|
|
|
91.4
|
|
Total Noncurrent Liabilities
|
4,615.4
|
|
|
4,561.8
|
|
Total Liabilities
|
5,148.3
|
|
|
5,022.6
|
|
Commitments and Contingencies (Refer to Note 17)
|
|
|
|
Temporary Equity
|
|
|
|
Redeemable noncontrolling interest
|
952.9
|
|
|
—
|
|
Equity
|
|
|
|
Common stock, $0.01 par value, 10,001,000 and 2,000,000,000 shares authorized, respectively; 10,000,150 and 399,841,350 shares outstanding, respectively
|
0.1
|
|
|
4.0
|
|
Additional paid-in capital
|
4,513.8
|
|
|
4,032.7
|
|
(Accumulated deficit) Retained earnings
|
(53.5
|
)
|
|
46.9
|
|
Accumulated other comprehensive loss
|
(23.9
|
)
|
|
(27.0
|
)
|
Total CPG Equity
|
4,436.5
|
|
|
4,056.6
|
|
Noncontrolling Interest
|
—
|
|
|
956.4
|
|
Total Equity
|
4,436.5
|
|
|
5,013.0
|
|
Total Liabilities, Temporary Equity and Equity
|
$
|
10,537.7
|
|
|
$
|
10,035.6
|
|
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
, (in millions)
|
2016
|
|
2015
|
|
2014
|
Operating Revenues
|
|
|
|
|
|
Transportation revenues
|
$
|
1,155.1
|
|
|
$
|
1,054.4
|
|
|
$
|
990.8
|
|
Transportation revenues-affiliated
|
—
|
|
|
47.5
|
|
|
95.7
|
|
Storage revenues
|
196.5
|
|
|
171.4
|
|
|
144.0
|
|
Storage revenues-affiliated
|
—
|
|
|
26.2
|
|
|
53.2
|
|
Other revenues
|
30.4
|
|
|
35.4
|
|
|
64.3
|
|
Total Operating Revenues
|
1,382.0
|
|
|
1,334.9
|
|
|
1,348.0
|
|
Operating Expenses
|
|
|
|
|
|
Operation and maintenance
|
863.2
|
|
|
652.1
|
|
|
628.4
|
|
Operation and maintenance-affiliated
|
—
|
|
|
52.9
|
|
|
123.2
|
|
Depreciation and amortization
|
172.8
|
|
|
139.9
|
|
|
118.8
|
|
Gain on sale of assets
|
(16.6
|
)
|
|
(55.3
|
)
|
|
(34.5
|
)
|
Impairment of long-lived assets
|
26.1
|
|
|
2.4
|
|
|
—
|
|
Property and other taxes
|
83.2
|
|
|
75.3
|
|
|
67.1
|
|
Total Operating Expenses
|
1,128.7
|
|
|
867.3
|
|
|
903.0
|
|
Equity Earnings in Unconsolidated Affiliates
|
64.3
|
|
|
60.5
|
|
|
46.6
|
|
Operating Income
|
317.6
|
|
|
528.1
|
|
|
491.6
|
|
Other Income (Deductions)
|
|
|
|
|
|
Interest expense
|
(119.1
|
)
|
|
(67.6
|
)
|
|
—
|
|
Interest expense-affiliated
|
(2.1
|
)
|
|
(29.3
|
)
|
|
(62.0
|
)
|
Other, net
|
35.1
|
|
|
29.3
|
|
|
8.8
|
|
Total Other Deductions, net
|
(86.1
|
)
|
|
(67.6
|
)
|
|
(53.2
|
)
|
Income from Continuing Operations before Income Taxes
|
231.5
|
|
|
460.5
|
|
|
438.4
|
|
Income Taxes
|
77.8
|
|
|
153.0
|
|
|
169.7
|
|
Income from Continuing Operations
|
153.7
|
|
|
307.5
|
|
|
268.7
|
|
Income (Loss) from Discontinued Operations-net of taxes
|
0.2
|
|
|
(0.4
|
)
|
|
(0.6
|
)
|
Net Income
|
153.9
|
|
|
307.1
|
|
|
$
|
268.1
|
|
Less: Net income attributable to noncontrolling interest
|
37.1
|
|
|
39.9
|
|
|
|
Net Income Attributable to CPG
|
$
|
116.8
|
|
|
$
|
267.2
|
|
|
|
Amounts Attributable to CPG:
|
|
|
|
|
|
Net income from continuing operations
|
$
|
116.6
|
|
|
$
|
267.6
|
|
|
$
|
268.7
|
|
Net income (loss) from discontinued operations-net of taxes
|
0.2
|
|
|
(0.4
|
)
|
|
(0.6
|
)
|
Net Income Attributable to CPG
|
$
|
116.8
|
|
|
$
|
267.2
|
|
|
$
|
268.1
|
|
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
STATEMENTS OF CONSOLIDATED AND COMBINED COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions, net of taxes)
|
2016
|
|
2015
|
|
2014
|
Net Income
|
$
|
153.9
|
|
|
$
|
307.1
|
|
|
$
|
268.1
|
|
Other comprehensive income
|
|
|
|
|
|
Net unrealized gain on cash flow hedges
(1)
|
1.3
|
|
|
0.2
|
|
|
1.0
|
|
Unrecognized pension and OPEB benefit (cost)
(2)(3)
|
2.0
|
|
|
5.2
|
|
|
(9.7
|
)
|
Total other comprehensive income (loss)
|
3.3
|
|
|
5.4
|
|
|
(8.7
|
)
|
Total Comprehensive Income
|
157.2
|
|
|
312.5
|
|
|
259.4
|
|
Less: Comprehensive Income-noncontrolling interest
|
37.3
|
|
|
40.0
|
|
|
—
|
|
Comprehensive Income-controlling interests
|
$
|
119.9
|
|
|
$
|
272.5
|
|
|
$
|
259.4
|
|
(1)
Net unrealized gain on derivatives qualifying as cash flow hedges, net of
$0.7 million
,
$0.2 million
and
$0.7 million
tax expense in
2016
,
2015
and
2014
, respectively.
(2)
Unrecognized pension and OPEB benefit (cost), net of
$1.3 million
tax expense,
$1.2 million
tax benefit, and
$6.1 million
tax benefit in
2016
,
2015
and
2014
, respectively.
(3)
Unrecognized pension and OPEB benefits are primarily related to pension and OPEB remeasurements recorded during 2016 and 2015.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Columbia Pipeline Group, Inc.
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, (in millions)
|
2016
|
|
2015
|
|
2014
|
Operating Activities
|
|
|
|
|
|
Net Income
|
$
|
153.9
|
|
|
$
|
307.1
|
|
|
$
|
268.1
|
|
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations:
|
|
|
|
|
|
Depreciation and amortization
|
172.8
|
|
|
139.9
|
|
|
118.8
|
|
Deferred income taxes and investment tax credits
|
129.4
|
|
|
131.9
|
|
|
142.6
|
|
Deferred revenue
|
(3.2
|
)
|
|
4.2
|
|
|
1.6
|
|
Equity-based compensation expense and profit sharing contribution
|
1.7
|
|
|
9.4
|
|
|
6.3
|
|
Gain on sale of assets
|
(16.6
|
)
|
|
(55.3
|
)
|
|
(34.5
|
)
|
Impairment of long-lived assets
|
26.1
|
|
|
2.4
|
|
|
—
|
|
Equity earnings in unconsolidated affiliates
|
(64.3
|
)
|
|
(60.5
|
)
|
|
(46.6
|
)
|
(Income) loss from discontinued operations-net of taxes
|
(0.2
|
)
|
|
0.4
|
|
|
0.6
|
|
Amortization of debt related costs
|
10.2
|
|
|
3.1
|
|
|
—
|
|
AFUDC equity
|
(34.9
|
)
|
|
(28.3
|
)
|
|
(11.0
|
)
|
Distributions of earnings received from equity investees
|
61.5
|
|
|
57.2
|
|
|
37.8
|
|
Changes in Assets and Liabilities:
|
|
|
|
|
|
Accounts receivable
|
(39.2
|
)
|
|
(17.4
|
)
|
|
(20.3
|
)
|
Accounts receivable-affiliated
|
(55.8
|
)
|
|
34.7
|
|
|
(3.6
|
)
|
Accounts payable
|
16.0
|
|
|
(5.0
|
)
|
|
2.8
|
|
Accounts payable-affiliated
|
3.4
|
|
|
(53.6
|
)
|
|
12.4
|
|
Customer deposits
|
(0.6
|
)
|
|
(22.9
|
)
|
|
77.5
|
|
Taxes accrued
|
8.8
|
|
|
8.2
|
|
|
12.0
|
|
Interest accrued
|
0.1
|
|
|
9.4
|
|
|
—
|
|
Exchange gas receivable/payable
|
(0.2
|
)
|
|
(0.3
|
)
|
|
1.1
|
|
Other accruals
|
1.7
|
|
|
50.2
|
|
|
0.9
|
|
Prepayments and other current assets
|
16.2
|
|
|
(27.1
|
)
|
|
(4.4
|
)
|
Regulatory assets/liabilities
|
11.2
|
|
|
20.2
|
|
|
9.0
|
|
Postretirement and postemployment benefits
|
(14.5
|
)
|
|
(4.4
|
)
|
|
(1.3
|
)
|
Deferred charges and other noncurrent assets
|
(8.0
|
)
|
|
(16.3
|
)
|
|
(4.3
|
)
|
Other noncurrent liabilities
|
(15.6
|
)
|
|
6.5
|
|
|
0.7
|
|
Net Operating Activities from Continuing Operations
|
359.9
|
|
|
493.7
|
|
|
566.2
|
|
Net Operating Activities from (used for) Discontinued Operations
|
0.3
|
|
|
(0.2
|
)
|
|
(1.4
|
)
|
Net Cash Flows from Operating Activities
|
360.2
|
|
|
493.5
|
|
|
564.8
|
|
Investing Activities
|
|
|
|
|
|
Capital expenditures
|
(1,438.1
|
)
|
|
(1,181.0
|
)
|
|
(747.2
|
)
|
Insurance recoveries
|
3.0
|
|
|
2.1
|
|
|
11.3
|
|
Changes in short-term lendings-affiliated
|
—
|
|
|
145.5
|
|
|
(57.2
|
)
|
Proceeds from disposition of assets
|
10.4
|
|
|
77.6
|
|
|
9.3
|
|
Contributions to equity investees
|
(6.2
|
)
|
|
(1.4
|
)
|
|
(69.2
|
)
|
Distributions from equity investees
|
2.2
|
|
|
16.0
|
|
|
—
|
|
Other investing activities
|
0.6
|
|
|
(27.4
|
)
|
|
(7.1
|
)
|
Net Cash Flows used for Investing Activities
|
(1,428.1
|
)
|
|
(968.6
|
)
|
|
(860.1
|
)
|
Financing Activities
|
|
|
|
|
|
Change in short-term borrowings
|
(15.0
|
)
|
|
15.0
|
|
|
—
|
|
Change in short-term borrowings-affiliated
|
500.0
|
|
|
(252.5
|
)
|
|
(467.1
|
)
|
Payment of short-term borrowings-affiliated
|
(500.0
|
)
|
|
—
|
|
|
—
|
|
Issuance of long-term debt
|
—
|
|
|
2,745.9
|
|
|
—
|
|
Payment of capital lease obligations and other debt related costs
|
(5.4
|
)
|
|
(23.6
|
)
|
|
(6.4
|
)
|
Issuance of long-term debt-affiliated
|
—
|
|
|
1,217.3
|
|
|
768.9
|
|
Payments of long-term debt-affiliated, including current portion
|
—
|
|
|
(2,807.8
|
)
|
|
—
|
|
Proceeds from issuance of common units, net of offering costs
|
—
|
|
|
1,168.4
|
|
|
—
|
|
Issuance of common stock, net of offering costs
|
—
|
|
|
1,394.7
|
|
|
—
|
|
Issuance of common stock to TransCanada
|
500.1
|
|
|
—
|
|
|
—
|
|
Distribution of IPO proceeds to NiSource
|
—
|
|
|
(500.0
|
)
|
|
—
|
|
Distribution to NiSource
|
—
|
|
|
(1,450.0
|
)
|
|
—
|
|
Distribution to noncontrolling interest
|
(41.0
|
)
|
|
(23.2
|
)
|
|
—
|
|
Acquisition of treasury stock
|
(6.2
|
)
|
|
—
|
|
|
—
|
|
Dividends paid - common stock
|
(105.1
|
)
|
|
(79.5
|
)
|
|
—
|
|
Dividends paid - TransCanada
|
(110.5
|
)
|
|
—
|
|
|
—
|
|
Transfer from NiSource
|
—
|
|
|
0.8
|
|
|
—
|
|
Net Cash Flows from Financing Activities
|
216.9
|
|
|
1,405.5
|
|
|
295.4
|
|
Change in cash and cash equivalents
|
(851.0
|
)
|
|
930.4
|
|
|
0.1
|
|
Cash and cash equivalents at beginning of period
|
930.9
|
|
|
0.5
|
|
|
0.4
|
|
Cash and Cash Equivalents at End of Period
|
$
|
79.9
|
|
|
$
|
930.9
|
|
|
$
|
0.5
|
|
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
C
olumbia Pipeline Group, Inc.
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Common Stock
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
(Accumulated Deficit) Retained Earnings
|
|
Net Parent Investment
|
|
Accumulated Other Comprehensive Loss
|
|
Total Equity
|
|
Noncontrolling Interest
(4)
|
Balance as of January 1, 2014 -
Predecessor
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,941.4
|
|
|
$
|
(25.8
|
)
|
|
$
|
3,915.6
|
|
|
$
|
—
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
268.1
|
|
|
—
|
|
|
268.1
|
|
|
—
|
|
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8.7
|
)
|
|
(8.7
|
)
|
|
—
|
|
Net transfers from parent
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.3
|
|
|
—
|
|
|
1.3
|
|
|
—
|
|
Balance as of December 31, 2014
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,210.8
|
|
|
$
|
(34.5
|
)
|
|
$
|
4,176.3
|
|
|
$
|
—
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
126.4
|
|
|
140.8
|
|
|
—
|
|
|
267.2
|
|
|
39.9
|
|
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.3
|
|
|
5.3
|
|
|
0.1
|
|
Allocation of AOCI to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.2
|
|
|
2.2
|
|
|
(2.2
|
)
|
Issuance of common units of CPPL
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,168.4
|
|
Distribution of IPO proceeds to NiSource
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(500.0
|
)
|
|
—
|
|
|
(500.0
|
)
|
|
—
|
|
Distribution to NiSource
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,450.0
|
)
|
|
—
|
|
|
(1,450.0
|
)
|
|
—
|
|
Sale of interest in Columbia OpCo to CPPL
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
227.1
|
|
|
—
|
|
|
227.1
|
|
|
(227.1
|
)
|
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23.2
|
)
|
Net transfers from NiSource prior to Separation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.3
|
|
|
—
|
|
|
6.3
|
|
|
—
|
|
Reclassification of net parent investment to additional paid-in capital
|
—
|
|
|
—
|
|
|
2,635.0
|
|
|
—
|
|
|
(2,635.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Issuance of common stock at Separation
|
3.2
|
|
|
—
|
|
|
(3.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net transfers from NiSource subsequent to Separation
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
0.5
|
|
Issuance of common stock, net of offering costs
|
0.8
|
|
|
—
|
|
|
1,393.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,394.7
|
|
|
—
|
|
Long-term incentive plan
|
—
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
Common stock dividends
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
(79.5
|
)
|
|
—
|
|
|
—
|
|
|
(79.5
|
)
|
|
—
|
|
Balance as of December 31, 2015
|
$
|
4.0
|
|
|
$
|
—
|
|
|
$
|
4,032.7
|
|
|
$
|
46.9
|
|
|
$
|
—
|
|
|
$
|
(27.0
|
)
|
|
$
|
4,056.6
|
|
|
$
|
956.4
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
116.8
|
|
|
—
|
|
|
—
|
|
|
116.8
|
|
|
37.1
|
|
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.1
|
|
|
3.1
|
|
|
0.2
|
|
Common stock dividends
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
(105.1
|
)
|
|
—
|
|
|
—
|
|
|
(105.1
|
)
|
|
—
|
|
Dividends to TransCanada
|
—
|
|
|
—
|
|
|
—
|
|
|
(110.5
|
)
|
|
—
|
|
|
—
|
|
|
(110.5
|
)
|
|
—
|
|
Common stock purchased by TransCanada and retired
|
(4.0
|
)
|
|
—
|
|
|
(10,212.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,216.7
|
)
|
|
—
|
|
Issuance of common stock associated with Merger
|
0.1
|
|
|
—
|
|
|
10,216.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,216.8
|
|
|
—
|
|
Treasury stock acquired
|
—
|
|
|
(6.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6.2
|
)
|
|
—
|
|
Treasury stock retirement
|
—
|
|
|
6.2
|
|
|
(4.6
|
)
|
|
(1.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41.0
|
)
|
Issuance of stock to TransCanada
(3)
|
—
|
|
|
—
|
|
|
500.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
500.0
|
|
|
—
|
|
Long-term incentive plan
|
—
|
|
|
—
|
|
|
(18.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18.3
|
)
|
|
0.2
|
|
Balance as of December 31, 2016
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
4,513.8
|
|
|
$
|
(53.5
|
)
|
|
$
|
—
|
|
|
$
|
(23.9
|
)
|
|
$
|
4,436.5
|
|
|
$
|
952.9
|
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
C
olumbia Pipeline Group, Inc.
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY
(1)
Represents the sale of an additional
8.4%
limited partner interest in Columbia OpCo, recorded at the historical carrying value of Columbia OpCo's net assets after giving effect to the
$1,168.4 million
equity contribution. This decreases the noncontrolling interest by the same amount it increases the net parent investment because CPPL's purchase price for its additional
8.4%
interest in Columbia OpCo exceeded book value.
(2)
CPG declared and paid common dividends totaling
$0.2625
per share and
$0.25
per share for the years ended
December 31, 2016
and
2015
, respectively.
(3)
In December 2016, CPG issued
50
shares of common stock,
$0.01
par value at a purchase price of
$10.0 million
per share, for a total of
$500.0 million
to US Parent.
(4)
As of December 31, 2016 and as a result of the CPPL Merger Agreement, CPPL's common units now contain a redemption feature within the control of CPPL's unaffiliated unitholders. The existence of the redemption feature causes CPG's noncontrolling interest to be redeemable at an amount other than fair value, thus requiring CPG to present noncontrolling interest as temporary equity on the Consolidated Balance Sheets. Please see Note 1, "Nature of Operations and Summary of Significant Accounting Policies" in the Notes to Consolidated and Combined Financial Statements for further discussion.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
|
|
1.
|
Nature of Operations and Summary of Significant Accounting Policies
|
A. Company Structure and Basis of Presentation
. Columbia Pipeline Group, Inc. ("CPG") is a growth-oriented Delaware corporation formed on September 26, 2014 to own, operate and develop a portfolio of pipelines, storage and related midstream assets. CPG owns and operates, through its subsidiaries, approximately
15,000
miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. CPG indirectly owns the general partner of CPPL and all of CPPL’s subordinated units and incentive distribution rights. CPG did not have any material assets or liabilities as a separate corporate entity until the contribution of CEG from NiSource on February 11, 2015. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows for CPG's Predecessor (the "Predecessor").
CPG is engaged in regulated gas transportation and storage services for LDCs, marketers, producers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses such as midstream services, including gathering, treating, conditioning, processing, compression and liquids handling and development of mineral rights positions. The regulated services are performed under a tariff at rates subject to FERC approval.
Separation.
On June 2, 2015, NiSource announced that its board of directors approved the separation of CPG from NiSource (the “Separation”) through the distribution of CPG common stock to holders of NiSource common stock as of June 19, 2015 (the “Record Date”). On July 1, 2015, NiSource distributed, pursuant to an effective registration statement on Form 10,
317.6 million
shares, one share of CPG common stock for every one share of NiSource common stock held by NiSource stockholders on the Record Date. As of July 1, 2015, CPG was an independent, publicly traded company, and NiSource did not retain any ownership interest in CPG. CPG's common stock began trading "regular-way" under the ticker symbol "CPGX" on the NYSE on July 2, 2015. In connection with the Separation, CPG completed the following transactions:
|
|
•
|
In May 2015, CPG completed its private placement of senior notes and received proceeds of approximately
$2,722.3 million
. CPG utilized a portion of the proceeds to repay approximately
$1,087.3 million
of intercompany debt and short-term borrowings, including, net amounts due from the money pool between CPG and NiSource Finance;
|
|
|
•
|
CPG further utilized the proceeds from the senior notes to make a cash distribution of approximately
$1,450.0 million
to NiSource; and
|
|
|
•
|
Accounts related to NiSource and its subsidiaries, including accounts receivable and accounts payable, were reclassified from affiliated to non-affiliated.
|
Agreements with NiSource following the Separation
. CPG entered into the Separation and Distribution Agreement and several other agreements with NiSource to effect the Separation and provide a framework for CPG’s relationship with NiSource, and its subsidiaries, after the Separation. The Separation and Distribution Agreement contains many of the key provisions related to CPG’s separation from NiSource and the distribution of CPG’s shares of common stock to NiSource’s stockholders, including cross-indemnities between CPG and NiSource. In general, NiSource has agreed to indemnify CPG for any liabilities relating to NiSource's business and CPG has agreed to indemnify NiSource for any liabilities relating to CPG's business. In addition to the Separation and Distribution Agreement, CPG entered into the following agreements with NiSource related to the Separation:
|
|
•
|
Tax Allocation Agreement - Provides for the respective rights, responsibilities, and obligations of NiSource and CPG with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, tax contests, and certain other matters regarding taxes.
|
|
|
•
|
Employee Matters Agreement - Provides for the respective obligations to employees and former employees who are or were associated with CPG (including those employees who transferred employment from NiSource to CPG prior to the Separation) and for other employment and employee benefits matters.
|
|
|
•
|
Transition Services Agreement - Provides for the provision of certain transitional services by NiSource to CPG, and vice versa. The services may include the provision of administrative and other services identified by the parties. The charge for these services is expected to be based on actual costs incurred by the party rendering the services without profit.
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Merger.
On
March 17, 2016
, CPG entered into an Agreement and Plan of Merger (the "Merger Agreement"), among CPG, TCPL, US Parent, Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent ("Merger Sub"), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the Merger Agreement, effective
July 1, 2016
, Merger Sub was merged with and into CPG (the "Merger") with CPG surviving the Merger as an indirect wholly owned subsidiary of TransCanada.
On
July 1, 2016
, TransCanada closed the acquisition of CPG valued at
$13.0 billion
, comprised of a purchase price of approximately
$10.3 billion
and CPG debt of approximately
$2.7 billion
. CPG became an indirect, wholly owned subsidiary of TransCanada as a result of the Merger. Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of CPG common stock, par value
$0.01
per share, was canceled and converted into the right to receive
$25.50
per share in cash, without interest. Upon completion of the transaction, TransCanada owns the general partner of CPPL, all of CPPL’s incentive distribution rights and all of CPPL's subordinated units, which represent a
46.5%
limited partnership interest in CPPL. As a result, CPPL is now effectively managed by TransCanada.
For the
year ended
December 31, 2016
, CPG incurred Merger transaction costs of
$66.6 million
, including legal, advisory and other related fees. These costs are included in "Operation and maintenance" on the Statements of Consolidated and Combined Operations. Approximately
$104.9 million
of employee related costs were incurred subsequent to the Merger. Additionally as a result of the Merger, CPG recognized an impairment charge of
$26.1 million
related to the cancellation of IT system upgrades that were in process prior to the Merger.
CPG has suspended its obligation to file periodic reports with the SEC based on its common stock as a result of the Merger. CPG has also suspended its obligations to file periodic reports with the SEC based on its senior notes and once it has filed its Form 10-K for the year ended December 31, 2016, it will no longer have reporting obligations with respect to its senior notes. Refer to Note 6, "Long-Term Debt" for additional information on CPG's senior notes.
CPPL Merger.
On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger ("CPPL Merger Agreement") with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.
The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the CPPL Merger Agreement and transactions contemplated by the CPPL Merger Agreement and determined that the CPPL Merger Agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the CPPL Merger Agreement and the merger transactions. The GP Board resolved that the CPPL Merger Agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the CPPL Merger Agreement and the merger transactions at the special meeting of the unitholders.
On February 16, 2017, the CPPL unaffiliated unitholders voted to approve the CPPL Merger. On February 17, 2017, CPG closed the transaction to acquire all outstanding publicly held common units valued at approximately
$915 million
. CPPL unaffiliated unitholders also received a regular quarterly distribution of
$0.1975
per common unit and a pro-rated distribution for the period prior to the closing date. As a result of the CPPL Merger, CPPL became a wholly owned subsidiary of CPG.
As of December 31, 2016 and as a result of the CPPL Merger Agreement, CPPL's common units now contain a redemption feature within the control of CPPL's unaffiliated unitholders. The existence of the redemption feature causes CPG's noncontrolling interest to be redeemable at an amount other than fair value, thus requiring CPG to present noncontrolling interest as temporary equity on the Consolidated Balance Sheets. The redeemable noncontrolling interest is recorded at its current book value and will be adjusted each period for net earnings and other comprehensive income attributable to the noncontrolling interest. As of December 31, 2016, CPG did not consider noncontrolling interest to be probable of becoming redeemable given the special meeting of CPPL's unitholders had not yet occurred and there could be no certainty the unaffiliated unitholders will vote to approve the merger.
CPG’s accompanying Consolidated and Combined Financial Statements have been prepared in accordance with GAAP. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream, CEVCO, CNS Microwave, Crossroads, CPGSC, CEG, Columbia Remainder Corporation, CPP GP LLC, CPPL, OpCo GP and Columbia OpCo. All intercompany transactions and balances have been eliminated. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline and Pennant.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
B. Use of Estimates.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
C. Cash and Cash Equivalents.
Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.
D. Allowance for Uncollectible Accounts.
The reserve for uncollectible receivables is CPG's best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
E. Basis of Accounting for Rate-Regulated Subsidiaries
. Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.
In the event that regulation significantly changes the opportunity for CPG to recover its costs in the future, all or a portion of CPG’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of CPG’s existing regulatory assets and liabilities could result. If CPG is unable to continue to apply the provisions of regulatory accounting, CPG would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, CPG’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 11, "Regulatory Matters," in the Notes to Consolidated and Combined Financial Statements for further discussion.
F. Property, Plant and Equipment and Related AFUDC and Maintenance
. Property, plant and equipment is stated at cost. CPG's rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. CPG's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties.
CPG capitalizes AFUDC on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and ADUFC equity are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
Debt
|
|
Equity
|
|
Debt
|
|
Equity
|
|
Debt
|
|
Equity
|
Columbia Gas Transmission
|
0.6
|
%
|
|
4.8
|
%
|
|
1.8
|
%
|
|
6.3
|
%
|
|
0.9
|
%
|
|
3.0
|
%
|
Columbia Gulf
|
0.6
|
%
|
|
3.7
|
%
|
|
2.9
|
%
|
|
6.3
|
%
|
|
2.1
|
%
|
|
9.4
|
%
|
CPG follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.
G. Gas Stored-Base Gas.
Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were
no
purchases of base gas during the years ended
December 31, 2016
,
2015
and
2014
. Gas stored-base gas is included in Property, plant and equipment on the Consolidated Balance Sheets.
H. Amortization of Software Costs.
External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
period of five years. CPG amortized
$20.4 million
in
2016
,
$8.7 million
in
2015
and
$4.3 million
in
2014
related to software costs. CPG’s unamortized software balance was
$72.1 million
and
$59.8 million
at December 31,
2016
and
2015
, respectively. The increase in software amortization and unamortized software balance is primarily due to software placed in service subsequent to the Separation. The additional software was necessary for CPG to operate as an independent company.
I. Goodwill.
CPG has
$1,975.5 million
in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the CEG acquisition on November 1, 2000. Please see Note 9, "Goodwill," in the Notes to Consolidated and Combined Financial Statements for further discussion.
J. Impairments.
An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long-lived assets is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long-lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. CPG recognized an impairment loss of
$26.1 million
,
$2.4 million
and
zero
for the years ended
December 31, 2016
,
2015
and
2014
, respectively. As a result of the Merger, CPG recognized an impairment loss for the year ended
December 31, 2016
related to the cancellation of IT system upgrades that were in process prior to the Merger.
K. Revenue Recognition.
Revenue is recorded as services are performed. Revenues are billed to customers monthly at rates established through the FERC's cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.
The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues for both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.
CPG provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided.
Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
CPG includes the subsidiary CEVCO, which owns the mineral rights to approximately
460,000
acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realized. Royalty revenue was
$21.5 million
,
$26.5 million
and
$43.8 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations.
CPG periodically recognizes gains on the conveyance of mineral interest related to pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if CPG has a substantial obligation for future performance. As the obligation for future performance is satisfied, the deferred revenue is relieved and the associated gain is recognized. Gains on conveyances amounted to
$16.9 million
,
$52.3 million
and
$34.5 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations.
L. Estimated Rate Refunds
. CPG collects revenue subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.
M. Accounting for Exchange and Balancing Arrangements of Natural Gas.
CPG enters into balancing and exchange arrangements of natural gas as part of its operations. CPG records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on CPG’s Consolidated Balance Sheets, as appropriate.
N. Income Taxes and Investment Tax Credits.
CPG records income taxes to recognize full inter period tax allocations. Under the liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. To the extent certain deferred income taxes of CPG are recoverable or payable through future rates, regulatory assets and liabilities have been established.
Subsequent to the Merger, CPG is included in the consolidated Federal income tax return filed by US Parent and is a party to a Federal Tax Allocation Agreement with US Parent. The tax allocation agreement allocates to CPG an amount of Federal income tax liabilities and benefits similar to that which would be if CPG had filed a separate return. For states that require consolidated or combined returns, CPG will be included with certain TransCanada affiliates and will settle its state income tax liabilities and benefits with US Parent.
In prior years, and for the period ending July 1, 2015, CPG joined in the filing of consolidated federal and state income tax returns with NiSource. CPG was a party to an agreement (“Tax Allocation Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Allocation Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, the Tax Allocation Agreement provides that tax benefits associated with NiSource parent’s tax losses, excluding tax benefits from interest expense on acquisition debt, are allocated to and reduce the income tax liability of all NiSource subsidiaries having a positive separate company tax liability in a particular tax year.
The amounts of such tax benefits allocated to CPG that were recorded in equity in
2016
,
2015
and
2014
were
zero
,
$5.8 million
and
$1.3 million
, respectively.
O. Environmental Expenditures.
CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The reserves for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Other Accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. CPG establishes regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 17, "Other Commitments and Contingencies" in the Notes to Consolidated and Combined Financial Statements for further discussion.
P. Accounting for Investments.
CPG accounts for its ownership interests in Millennium Pipeline using the equity method of accounting. Columbia Gas Transmission owns a
47.5%
interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where CPG (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.
CPG owns a
50.0%
interest in Hardy Storage for the periods presented. CPG reflects the investment in Hardy Storage as an equity method investment.
Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. During the third quarter of 2015, an additional member, an affiliate of Williams Partners, joined the Pennant joint venture. Williams Partners' initial ownership investment in Pennant is
5.00%
, and by funding specified investment amounts for future growth projects, Williams Partners can invest directly in the growth of Pennant. Such funding will potentially increase Williams Partners' ownership in Pennant up to
33.33%
over a defined investment period. As a result of the buy-in, Columbia Midstream received
$12.7 million
in cash and recorded a gain of
$2.9 million
, and its ownership interest in Pennant decreased from
50.0%
to
47.5%
. During 2016, Williams Partners funded additional specified growth projects. As a result Columbia Midstream's ownership interest decreased to
47.0%
. CPG accounts for the joint venture under the equity method of accounting.
Q. Natural Gas and Oil Properties.
CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors.
The following table reflects the changes in capitalized exploratory well costs for the years ended
December 31, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
|
2015
|
Beginning Balance
|
$
|
1.7
|
|
|
$
|
14.9
|
|
Additions pending the determination of proved reserves
|
—
|
|
|
1.3
|
|
Reclassifications of proved properties
|
(1.3
|
)
|
|
(14.5
|
)
|
Ending Balance
|
$
|
0.4
|
|
|
$
|
1.7
|
|
As of
December 31, 2016
, there was
$0.3 million
of capitalized exploratory well costs that have been capitalized for more than one year relating to
one
project initiated in 2013.
2. CPPL Initial Public Offering
On December 5, 2007, NiSource formed CPPL (NYSE: CPPL) to own, operate and develop a portfolio of pipelines, storage and related assets.
On
February 11, 2015
, CPPL completed its offering of
53.8 million
common units representing limited partner interests, constituting
53.5%
of CPPL's outstanding limited partner interests. CPPL received
$1,168.4 million
of net proceeds from the IPO. CPG owns the general partner of CPPL and all of CPPL's subordinated units and incentive distribution rights. The assets of CPPL consist of a
15.7%
limited partner interest in Columbia OpCo, which prior to the Separation, consisted of substantially all of NiSource's Columbia Pipeline Group Operations segment. The operations of CPPL are consolidated into CPG's results. As of
December 31, 2016
, the portion of CPPL owned by the public is reflected as a noncontrolling interest in the Consolidated and Combined Financial Statements.
The table below summarizes the effects of the changes in CPG's ownership interest in Columbia OpCo on equity:
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
Net income attributable to CPG
|
$
|
116.8
|
|
|
$
|
267.2
|
|
Increase in CPG's net parent investment for the sale of 8.4% of Columbia OpCo
|
—
|
|
|
227.1
|
|
Change from net income attributable to CPG and transfers to noncontrolling interest
|
$
|
116.8
|
|
|
$
|
494.3
|
|
|
|
3.
|
Recent Accounting Pronouncements
|
In January 2017, the FASB issued ASU 2017-04,
Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
. ASU 2017-04 simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. CPG is required to adopt ASU 2017-04 for its annual or any interim goodwill impairment tests for annual periods beginning after December 15, 2019, and the guidance is to be applied on a prospective basis. CPG is currently evaluating the impact the adoption of ASU 2017-04 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.
In January 2017, the FASB issued ASU 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
, to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. ASU 2017-01 provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. CPG is required to adopt ASU 2017-01 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied on a
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
prospective basis. CPG is currently evaluating the impact the adoption of ASU 2017-01 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.
In October 2016, the FASB issued ASU 2016-17,
Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control
, which amends the guidance on related parties that are under common control. Specifically, ASU 2016-17 requires that a single decision maker consider indirect interest held by related parties under common control on a proportionate basis in a manner consistent with its evaluation of indirect interests held through other related parties. CPG is required to adopt ASU 2016-17 for periods beginning after December 15, 2016, including interim periods, and the guidance is to be applied on a retrospective basis. CPG is currently evaluating the impact the adoption of ASU 2016-17 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate the impact will be material.
In October 2016, the FASB issued ASU 2016-16,
Income Taxes (Topic 740): Intra-Entity Asset Transfers of Assets Other Than Inventory
, which removes the prohibition in ASC 740 against the immediate recognition of the current and deferred income tax effects of intra-entity transfers of assets other than inventory. CPG is required to adopt ASU 2016-16 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied on a modified retrospective basis, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2016-16 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.
In August 2016, the FASB issued ASU 2016-15,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
. ASU 2016-15 amends the guidance in ASC 230 on the classification of certain cash receipts and payments in the statement of cash flows. CPG is required to adopt ASU 2016-15 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied retrospectively, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2016-15 will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers (Topic 606).
ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2017, including interim periods, and the new standard is to be applied retrospectively, with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. In March 2016, the FASB issued ASU 2016-08, which amends the principal-versus-agent implementation guidance and illustrations in ASU 2014-09. Among other things, ASU 2016-08 clarifies that an entity should evaluate whether it is the principal or the agent for each specified good or service promised in a contract with a customer. In April 2016, the FASB issued ASU 2016-10, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, which contains narrow scope improvements for certain aspects of ASU 2014-09 including collectability, presentation of sales tax and other similar taxes collected from customers, noncash consideration, contract modifications and completed contracts at transition and transition technical correction. CPG is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine the impact the adoption of ASU 2014-09, and the related ASUs, will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
In March 2016, the FASB issued ASU 2016-09,
Improvements to Employee Share-Based Payment Accounting (Topic 718)
. ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other provisions, ASU 2016-09 requires that all income tax effects of awards are recognized in the income statement when the awards vest or are settled and also allows an employer to make a policy election to account for forfeitures as they occur. CPG is required to adopt ASU 2016-09 for periods beginning after December 15, 2016, including interim periods, with early adoption permitted if all of the amendments are adopted in the same period. Each amendment has varying transition requirements. CPG expects to adopt ASU 2016-09 in the first quarter of 2017. Upon adoption, CPG will record a
$9.9 million
increase to beginning retained earnings with a corresponding increase in deferred tax assets representing the excess tax benefits generated in years prior to adoption of ASU 2016-09. Prior to the adoption of ASU 2016-09, CPG was precluded from recording this increase in deferred tax assets due to having a cumulative net operating loss carryforward for Federal income taxes.
In February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842)
. ASU 2016-02 introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in ASC 606, the FASB's new revenue recognition standard (e.g., those related to evaluating when profit can be recognized). Furthermore, ASU 2016-02 addresses other concerns related to the current leases model. For example, ASU 2016-02 eliminates the requirement in current U.S. GAAP for an entity to use bright-line tests in determining lease classification. The standard also requires lessors to increase the transparency of their exposure to changes in value of their residual assets and how they manage that exposure. CPG is required to adopt ASU 2016-02 for periods beginning after December 15, 2018, including interim periods, with early adoption permitted. CPG is currently identifying existing lease agreements that may have an impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
In April 2015, the FASB issued ASU 2015-03,
Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.
ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. In August 2015, the FASB issued ASU 2015-15 to clarify the SEC staff's position on these costs in relation to line-of-credit agreements stating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of such arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. CPG adopted ASU 2015-03 and ASU 2015-15 as of January 1, 2016, resulting in the reclassification of unamortized balance of debt issuance costs from "Deferred charges and other" to "Long-term debt." This change in accounting principle was applied retrospectively. As of December 31, 2015, the balance of unamortized debt issuance costs recorded in "Deferred charges and other" was
$20.6 million
. As a result of the retrospective adjustment, the December 31, 2015 balances of "Deferred charges and other" and "Long-term debt" were reduced by
$20.6 million
on the Consolidated Balance Sheets and Notes to Consolidated and Combined Financial Statements.
In February 2015, the FASB issued ASU 2015-02,
Consolidation (Topic 810): Amendments to the Consolidation Analysis
. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. CPG retrospectively adopted ASU 2015-02 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
4. Transactions with Affiliates
Transactions with TransCanada
Subsequent to the completion of the Merger, CPG engaged in transactions with subsidiaries of TransCanada, which are deemed to be affiliates of CPG. Transactions with affiliates subsequent to the Merger are summarized below:
Interest Expense.
CPG was charged interest for short-term borrowings of
$2.1 million
for the year ended December 31, 2016.
Accounts Receivable
. The affiliated accounts receivable balance of
$55.8 million
due from TransCanada primarily represents amounts allocated to CPG pursuant to TransCanada's tax allocation agreement.
Accounts Payable
. The affiliated accounts payable balance of
$4.0 million
primarily includes amounts due for insurance coverage and interest payable to TransCanada.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG-TransCanada PipeLine USA Ltd. Revolving Credit Facility.
Subsequent to the completion of the Merger, CPG entered into a
$2,000.0 million
revolving credit facility with US Parent. The revolving credit facility became effective as of July 1, 2016, with no termination date. The revolving credit facility is available for general corporate purposes, including capital expenditures.
Loans under the revolving credit facility bear interest at CPG's option at either (i) the greatest of (a) the federal funds effective rate plus
0.500 percent
per annum, (b) the reference prime rate per annum as defined by Bloomberg Professional Service or (c) the rate equal to LIBOR for a one month LIBOR period for each day the loan is outstanding, plus
1.000 percent
per annum, each of which is subject to a margin of
0.250 percent
per annum, or (ii) the LIBOR rate plus a margin of
1.250 percent
per annum.
As of
December 31, 2016
, CPG had
no
outstanding borrowings under the revolving credit facility, with a weighted average interest rate of
1.98%
.
Dividends to TransCanada
. Subsequent to the completion of the Merger, CPG distributed
$110.5 million
to TransCanada for the
year ended
December 31, 2016
.
Transactions with NiSource
Prior to the Separation, CPG engaged in transactions with subsidiaries of NiSource, which at that time were deemed to be affiliates of CPG. The Separation occurred on July 1, 2015 and for periods after this date CPG and subsidiaries of NiSource are no longer affiliates. Transactions with affiliates prior to the Separation are summarized below:
Transportation, Storage and Other Revenues
. CPG provided natural gas transportation, storage and other services to subsidiaries of NiSource, former affiliates. For the year ended
December 31, 2015
, CPG recognized transportation revenues of
$47.5 million
, storage revenues of
$26.2 million
and other revenues of
$0.2 million
. For the year ended
December 31, 2014
, CPG recognized transportation revenues of
$95.7 million
, storage revenues of
$53.2 million
and other revenues of
$0.3 million
.
Operation and Maintenance Expense
. CPG received executive, financial, legal, information technology and other administrative and general services from a former affiliate, NiSource Corporate Services. Expenses incurred as a result of these services consisted of employee compensation and benefits, outside services and other expenses. CPG was charged directly or allocated using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable. However, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity. For the years ended
December 31, 2015
and
2014
, operation and maintenance expense was
$52.9 million
and
$123.2 million
, respectively.
Interest Expense and Income
. Prior to the private placement of senior notes on May 22, 2015, CPG paid NiSource interest for intercompany long-term debt outstanding. CPG was charged interest for long-term debt of
$31.0 million
and
$61.6 million
for the years ended
December 31, 2015
and
2014
, respectively, offset by associated AFUDC of
$2.4 million
and
$2.7 million
for the years ended
December 31, 2015
and
2014
, respectively.
Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the closing date of CPPL's IPO. Following the Separation, the agreement is with CPG. The money pool is available for Columbia OpCo and its subsidiaries' general purposes, including capital expenditures and working capital. This intercompany money pool agreement is discussed in connection with Short-term Borrowings below. Prior to CPPL's IPO, the subsidiaries of CPG participated in a similar money pool agreement with NiSource Finance. Prior to the Separation, NiSource Corporate Services administered the money pools. Prior to the Separation, the cash accounts maintained by the subsidiaries of Columbia OpCo and CPG were swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and the subsidiary. The amount of interest expense and income for short-term borrowings was determined by the net position of each subsidiary in the money pool. Subsequent to the Separation, the intercompany money pool balances and related interest expense and income are eliminated as intercompany activity. The money pool weighted-average interest rate at June 30, 2015 was
1.21%
. The interest expense for short-term borrowings charged for the years ended
December 31, 2015
and
2014
was
$0.7 million
and
$3.1 million
, respectively.
Dividends to NiSource
. During the year ended
December 31, 2015
, CPG distributed
$500.0 million
of the proceeds from CPPL's IPO to NiSource as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo and
$1,450.0 million
of proceeds related to the issuance of senior notes in May 2015. CPG paid
no
dividends to NiSource in the
year ended
December 31, 2014
. There were no restrictions on the payment by CPG of dividends to NiSource.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
5. Short-Term Borrowings
New CPG Revolving Credit Facility.
On December 16, 2016, CPG entered into a
$1,000.0 million
senior revolving credit facility. The revolving credit facility is guaranteed by TCPL. The initial maturity date is December 15, 2017, subject to an extension permitted under the revolving credit facility. CPG expects that the revolving credit facility will be utilized for the financing of capital expenditures and for CPG’s general corporate purposes, including working capital. Obligations under the revolving credit facility are unsecured.
Loans under the revolving credit facility will bear interest at CPG's option at either (i) LIBOR plus a margin ranging from
0.75%
to
1.25%
or (ii) a base rate plus a margin ranging from
0.00%
to
0.25%
, in each case, depending upon the credit rating of the TCPL’s senior, unsecured, long-term debt (the "Index Debt Rating"). In addition, CPG is obligated to pay a quarterly commitment fee equal to a rate per annum ranging from
0.04%
to
0.15%
, depending upon the Index Debt Rating, and calculated daily based on the unused commitments during such previous quarter.
TCPL shall comply, and shall cause CPG and each of TCPL’s subsidiaries to comply, with a number of customary affirmative and negative covenants, including limitations with respect to liens, indebtedness, distributions, mergers, consolidations, and asset sales, among others. TCPL shall not, and shall not permit any of its subsidiaries to, incur additional indebtedness (other than indebtedness maturing 24 months or less after such indebtedness is incurred) if immediately after incurring such indebtedness, the ratio of indebtedness of TCPL and its subsidiaries (on a consolidated basis) to the total capitalization of TCPL and its subsidiaries (on a consolidated basis) would be in excess of
0.75
to
1.00
.
A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable (subject to applicable grace periods).
As of
December 31, 2016
, CPG had
no
outstanding borrowings under the revolving credit facility.
As of
December 31, 2015
, CPG had
no
outstanding borrowings and had
$18.1 million
in letters of credit under the previous revolving credit facility. On July 1, 2016, in connection with the Merger, all existing letters of credit were migrated to a TransCanada credit facility and the CPG revolving credit facility was terminated. As a result, CPG accelerated the amortization of
$4.3 million
of deferred costs associated with the revolving credit facility, which is included in interest expense for the
year ended
December 31, 2016
.
CPPL Revolving Credit Facility.
As of
December 31, 2015
, CPPL had
$15.0 million
in outstanding borrowings, with a weighted average interest rate of
1.28%
, and issued
no
letters of credit under the revolving credit facility. On June 29, 2016, in anticipation of the Merger, all outstanding borrowings, facility fees and interest were paid in full and the revolving credit facility was terminated. As a result, CPPL accelerated the amortization of
$1.4 million
of deferred costs associated with the revolving credit facility, which is included in interest expense for the
year ended
December 31, 2016
.
CPG Commercial Paper Program.
CPG's commercial paper program (the "Program") had a Program limit of up to
$1,000.0 million
. CEG, OpCo GP and Columbia OpCo each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the promissory notes. As of
December 31, 2015
, CPG had
no
promissory notes outstanding under the Program. On June 30, 2016, in anticipation of the Merger, the Program was terminated. CPG had
no
promissory notes outstanding under the Program at the time of termination.
Given their maturity and turnover is three months or less, cash flows related to the borrowings and repayments of the CPG and CPPL revolving credit facilities and the Program are presented net in the Statements of Consolidated and Combined Cash Flows.
Senior notes issuance.
On
May 22, 2015
, CPG issued a private placement of
$2,750.0 million
in aggregate principal amount of senior notes, comprised of
$500.0 million
of
2.45%
senior notes due 2018 (the "2018 Notes"),
$750.0 million
of
3.30%
senior notes due 2020 (the "2020 Notes"),
$1,000.0 million
of
4.50%
senior notes due 2025 (the "2025 Notes") and
$500.0 million
of
5.80%
senior notes due 2045 (the “2045 Notes” and, together with the 2018 Notes, 2020 Notes and 2025 Notes, the “Notes”).
The initial Guarantors are three subsidiaries of CPG, CEG, Columbia OpCo and OpCo GP. The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all of the Guarantors. Each guarantee of CPG’s obligations under
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
the Notes is a direct, unsecured and unsubordinated obligation of the applicable Guarantor and has the same ranking with respect to indebtedness of that Guarantor as the Notes have with respect to CPG’s indebtedness.
The guarantees of any Guarantor may be released under certain circumstances. First, if CPG discharges or defeases its obligations with respect to the Notes of any series, then any guarantee will be released with respect to that series. Second, if no event of default has occurred and is continuing under the Indenture, a Guarantor will be automatically and unconditionally released and discharged from its guarantee (i) at any time after June 1, 2018, upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not CPG’s affiliate, of all of CPG’s direct or indirect limited partnership, limited liability or other equity interests in the Guarantor; (ii) upon the merger of a guarantor into CPG or any other Guarantor or the liquidation and dissolution of such Guarantor; or (iii) at any time after June 1, 2018, upon release of all guarantees or other obligations of the Guarantor with respect to any of CPG’s funded debt, except the Notes.
The Indenture governing the Notes, dated as of May 22, 2015, contains covenants that, among other things, limit the ability of CPG and certain of its subsidiaries to incur liens, to enter into sale and lease-back transactions and to enter into mergers, consolidations or transfers of all or substantially all of their assets. The Indenture also contains customary events of default.
The 2018 Notes will mature on
June 1, 2018
, the 2020 Notes will mature on
June 1, 2020
, the 2025 Notes will mature on
June 1, 2025
and the 2045 Notes will mature on
June 1, 2045
. Interest on the Notes of each series will be payable semi-annually in arrears on June 1 and December 1.
On February 23, 2016, CPG filed an exchange offer registration statement with the SEC. The registration statement was declared effective as of April 14, 2016. The exchange offer contemplated by the registration statement expired on May 12, 2016. A post-effective amendment to the registration statement was filed on January 30, 2017 to terminate the registration of any senior notes under the registration statement that remained unexchanged.
The following table summarizes the aggregate maturities of long-term debt outstanding as of
December 31, 2016
:
|
|
|
|
|
Year Ending December 31,
(in millions)
|
|
2017
|
$
|
—
|
|
2018
|
500.0
|
|
2019
|
—
|
|
2020
|
750.0
|
|
2021
|
—
|
|
After
|
1,500.0
|
|
Total
(1)
|
$
|
2,750.0
|
|
(1)
This amount excludes unamortized discount and unamortized debt issuance costs of
$3.4 million
and
$18.0 million
, respectively. The unamortized discount and unamortized debt issuance costs applicable to the Notes are being amortized over the weighted average life of the Notes.
7. Gain on Sale of Assets
CPG recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. For the years ended
December 31, 2016
,
2015
and
2014
, gains on conveyances amounted to
$16.9 million
,
$52.3 million
and
$34.5 million
, respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of
$9.0 million
and
$35.8 million
received by CEVCO during the years ended
December 31, 2016
and
2015
, respectively, for the lease of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. As of
December 31, 2016
and
2015
, deferred gains of approximately
$0.3 million
and
$8.1 million
, respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated Balance Sheets.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
|
|
8.
|
Property, Plant and Equipment
|
CPG’s property, plant and equipment on the Consolidated Balance Sheets are classified as follows:
|
|
|
|
|
|
|
|
|
At December 31,
(in millions)
|
2016
|
|
2015
|
Property, plant and equipment
|
|
|
|
Pipeline and other transmission assets
|
$
|
6,681.2
|
|
|
$
|
6,160.4
|
|
Storage facilities
|
1,415.3
|
|
|
1,370.1
|
|
Gas stored base gas
|
299.5
|
|
|
299.5
|
|
Gathering and processing facilities
|
566.9
|
|
|
370.2
|
|
Construction work in process
|
1,097.0
|
|
|
487.6
|
|
General plant, software, and other assets
|
401.3
|
|
|
364.5
|
|
Property, plant and equipment
|
10,461.2
|
|
|
9,052.3
|
|
Accumulated depreciation and amortization
|
(3,126.2
|
)
|
|
(2,988.6
|
)
|
Net property, plant and equipment
|
$
|
7,335.0
|
|
|
$
|
6,063.7
|
|
The table below lists CPG's applicable annual depreciation rates:
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Depreciation rates
|
|
|
|
|
|
Pipeline and other transmission assets
|
1.00% - 2.50%
|
|
1.00% - 2.50%
|
|
1.00% - 2.50%
|
Storage facilities
|
2.19% - 3.00%
|
|
2.19% - 3.00%
|
|
2.19% - 3.30%
|
Gathering and processing facilities
|
1.67% - 2.50%
|
|
1.67% - 2.50%
|
|
1.67% - 2.50%
|
General plant, software, and other assets
|
1.00% - 20.00%
|
|
1.00% - 21.00%
|
|
1.00% - 10.00%
|
CPG tests its goodwill for impairment annually as of May 1 unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, referred to as the Columbia Gas Transmission Operations reporting unit, which is consistent with
the level of discrete financial information reviewed by management. The Columbia Gas Transmission Operations reporting unit includes the following entities: Columbia Gas Transmission (including its equity method investment in the Millennium Pipeline joint venture), Columbia Gulf and the equity method investment in Hardy Storage. All of CPG's goodwill relates to NiSource's acquisition of CEG in 2000, which was contributed to CPG prior to the Separation. CPG's goodwill assets at
December 31, 2016
and
December 31, 2015
were
$1,975.5 million
.
The Predecessor completed a quantitative ("step 1") fair value measurement of the reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed.
In estimating the fair value of Columbia Gas Transmission Operations for the May 1, 2012 test, the Predecessor used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Predecessor utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated with the assistance of a third-party valuation firm, using multiples and assumptions inherent in today’s market. The degree of judgment involved and reliability of inputs into each model were considered in weighting the various approaches. The resulting estimate of fair value of the reporting unit, using the weighted average of the income and market approaches, exceeded its carrying value, indicating that no impairment exists under step 1 of the annual impairment test.
Certain key assumptions used in determining the fair value of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Predecessor used the discount rate of
5.60%
for Columbia Gas Transmission Operations, resulting in excess fair value of approximately
$1,643.0 million
.
GAAP allows entities testing goodwill for impairment the option of performing a qualitative ("step 0") assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that, based on that assessment, it is more likely than not that its fair value is less than its carrying amount.
CPG applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2016. For the current year test, CPG assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The recent Merger Agreement and acquisition price were incorporated into the current year testing. The results of this assessment indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value.
CPG considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. In consideration of all relevant factors, there were no indicators that would require goodwill impairment testing subsequent to May 1, 2016.
|
|
10.
|
Asset Retirement Obligations
|
Changes in CPG’s liability for asset retirement obligations for the years
2016
and
2015
are presented in the table below:
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
|
2015
|
Beginning Balance
|
$
|
25.7
|
|
|
$
|
23.2
|
|
Accretion expense
|
1.1
|
|
|
1.2
|
|
Additions
|
—
|
|
|
4.1
|
|
Change in estimated cash flows
|
(6.0
|
)
|
|
(2.8
|
)
|
Ending Balance
|
$
|
20.8
|
|
|
$
|
25.7
|
|
CPG's asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl ("PCB") remediation and asbestos removal at several compressor and measuring stations. CPG recognizes that certain assets, which include gas pipelines and natural gas storage wells, will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Regulatory Assets and Liabilities
Current and noncurrent regulatory assets and liabilities were comprised of the following items:
|
|
|
|
|
|
|
|
|
At December 31,
(in millions)
|
2016
|
|
2015
|
Assets
|
|
|
|
Unrecognized pension benefit and other postretirement benefit costs
|
$
|
111.3
|
|
|
$
|
135.2
|
|
Other postretirement costs
|
6.3
|
|
|
9.0
|
|
Deferred taxes on AFUDC equity
|
57.0
|
|
|
35.4
|
|
Other
|
2.3
|
|
|
3.1
|
|
Total Regulatory Assets
|
$
|
176.9
|
|
|
$
|
182.7
|
|
|
|
|
|
|
|
|
|
|
At December 31,
(in millions)
|
2016
|
|
2015
|
Liabilities
|
|
|
|
Cost of removal
|
$
|
141.5
|
|
|
$
|
154.7
|
|
Regulatory effects of accounting for income taxes
|
10.2
|
|
|
10.6
|
|
Modernization revenue sharing
|
7.4
|
|
|
—
|
|
Other postretirement costs
|
134.3
|
|
|
155.6
|
|
Other
|
—
|
|
|
1.9
|
|
Total Regulatory Liabilities
|
$
|
293.4
|
|
|
$
|
322.8
|
|
No
regulatory assets are earning a return on investment at
December 31, 2016
. Regulatory assets of
$58.9 million
are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to
6
years.
Assets:
Unrecognized pension benefit and other postretirement benefit costs –
In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders to be recovered through base rates.
Other postretirement costs –
Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.
Deferred taxes on AFUDC equity -
ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. CPG is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized.
Liabilities:
Cost of removal
- Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of some rate-regulated subsidiaries for future costs to be incurred.
Regulatory effects of accounting for income taxes
- Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates, which is being amortized to earnings in association with depreciation on related property.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Modernization revenue sharing
- Represents amounts related to the revenue sharing mechanism within the Columbia Gas Transmission modernization program. The revenue sharing mechanism requires Columbia Gas Transmission to share 75% of specified revenues in excess of an annual threshold.
Other postretirement costs
- Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the CPG's results, which exceeds the amount funded in the plan.
Regulatory Matters
Columbia Gas Transmission Customer Settlement.
On January 24, 2013, the FERC approved the Columbia Gas Transmission Customer Settlement (the "MOD I Settlement"). In March 2013, Columbia Gas Transmission paid
$88.1 million
in refunds to customers pursuant to the MOD I Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a
$50.0 million
refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately
$1.5 billion
over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The MOD I Settlement with firm customers included an initial five-year term with provisions for potential extensions thereafter.
The MOD I Settlement also provided for a depreciation rate reduction to
1.5%
and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately
$25.0 million
in revenues annually thereafter.
The MOD I Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a
14.0%
revenue requirement with a portion designated as a recovery of taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a
$1.5 billion
investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with
$100.0 million
in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission's transportation shippers. The CCRM will not exceed
$300.0 million
per year in investment in eligible facilities, subject to a
15.0%
annual tolerance and a total cap of
$1.5 billion
for the entire five-year initial term.
On January 31, 2017, Columbia Gas Transmission received FERC approval of its December 2016 filing to recover costs associated with the fourth year of its comprehensive system modernization program. In 2016, Columbia Gas Transmission placed approximately
$330.0 million
in modernization investments into service, bringing the total gross investment to approximately
$1.3 billion
over the four year period. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.
On March 17, 2016, Columbia Gas Transmission received approval from the Commission of its December 18, 2015 filing for the Modernization II Settlement (the "MOD II Settlement"). The MOD II Settlement continues a rate mechanism that was designed to enable Columbia Gas Transmission to recover costs associated with a multi-year modernization program focused on replacing, rehabilitating and/or rebuilding critical pipeline infrastructure and ensuring the safety and reliability of the Columbia Gas Transmission system.
The MOD II Settlement preserves and extends the core elements of the MOD I Settlement between Columbia Gas Transmission and its shippers that addressed previous modernization issues on the Columbia Gas Transmission system for three additional years. Columbia Gas Transmission expects to invest approximately
$1.1 billion
over the three-year extension period. Among other things, the MOD II Settlement preserves the MOD I Settlement’s
$60.0 million
base rate reduction and extends for a second term the CCRM that allows Columbia Gas Transmission to make annual limited filings under Section 4 of the Natural Gas Act to charge an additive capital demand rate in order to recover the revenue requirement related to certain eligible projects.
The MOD II Settlement includes an additional reduction in base rates equal to approximately
$8.4 million
annually effective as of January 1, 2016, discontinuing the collection of OPEB costs no longer required because of the substantial over-recovered position, and a further base rate reduction equal to approximately
$12.4 million
annually for a 6-year period also beginning January
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
1, 2016, which basically refunds amounts to customers as a result of the over-collection of OPEB costs. Columbia Gas Transmission's base rates will reset effective February 1, 2019, without the need for a rate case, and a simultaneous reduction in those base rates equal to
$7.5 million
annually. The MOD II Settlement includes a one-time
$5.0 million
settlement payment effective after FERC’s approval of the 5th year CCRM for recovery under the first phase; payment would not be expected until 2018, and a revenue sharing mechanism, which requires Columbia Gas Transmission to share
50.0%
of specified revenues in excess of an annual threshold. Columbia Gas Transmission has agreed to maintain a transmission depreciation rate of
1.5%
, a storage depreciation rate of
2.2%
, a negative salvage rate of
zero percent
and a moratorium through January 31, 2022 to changes in Columbia Gas Transmission’s base rates. The MOD II Settlement includes specified storage projects as eligible facilities whereby Columbia Gas Transmission may undertake construction of additional eligible facility projects in 2016-2017, with cost recovery on those projects beginning in 2019.
Columbia Gulf.
On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf's existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf filed a cost and revenue study with the FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. On June 13, 2016, the FERC trial staff, Columbia Gulf, and all of the active parties filed a Joint Motion to Suspend the Procedural Schedule and Waive Answer Period (the "Motion"). The Motion represents that the parties unanimously support the Motion and requested waiver of the answer period, which was granted. The parties reached an agreement in principle during a June 2, 2016 settlement conference that would fully resolve all matters set for hearing by the FERC. The Motion represents that the parties expect to file an offer of settlement memorializing the agreement in principle no later than July 29, 2016, and suspension of the procedural schedule will promote an efficient and speedy resolution of this matter by allowing the participants to focus their efforts on drafting the necessary settlement documents. Columbia Gulf filed the offer of settlement with the FERC in accordance with the agreement noted above.
On August 15, 2016, the administrative law judge issued a Certification of Uncontested Settlement, which noted that no parties objected to the provisions in the offer of settlement. On September 22, 2016, the FERC issued an order approving the uncontested settlement, which requires a reduction in Columbia Gulf’s daily maximum recourse rate and addresses Columbia Gulf’s treatment of postretirement benefits other than pensions, pension expenses, and regulatory expenses. The order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020. Other terms of the settlement are included in FERC Docket No. RP16-302-000.
Cost Recovery Trackers and other similar mechanisms.
Under section 4 of the NGA, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect.
A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015.
Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel. The recoveries and costs are both reflected in operating expenses.
|
|
12.
|
Equity Method Investments
|
Certain investments of CPG are accounted for under the equity method of accounting. These investments are recorded within "Unconsolidated Affiliates" on CPG's Consolidated Balance Sheets and CPG's portion of the results is reflected in "Equity Earnings in Unconsolidated Affiliates" on CPG's Statements of Consolidated and Combined Operations. In the normal course of business, CPG engages in various transactions with these unconsolidated affiliates. CPG billed approximately
$10.5 million
and
$13.1 million
to Millennium Pipeline for services and other costs during the years ended
December 31, 2016
and
2015
, respectively. These investments are integral to CPG's business. Contributions are made to these equity investees to fund CPG's share of projects.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following is a list of CPG's equity method investments at
December 31, 2016
:
|
|
|
|
|
Investee
|
Type of Investment
|
% of Voting Power or Interest Held
|
Hardy Storage Company, LLC
|
LLC Membership
|
50.0
|
%
|
Pennant Midstream, LLC
|
LLC Membership
|
47.0
|
%
|
Millennium Pipeline Company, L.L.C.
|
LLC Membership
|
47.5
|
%
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in aggregate, material to CPG's business, the following table contains condensed summary financial data.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Millennium Pipeline
|
|
|
|
|
|
Statement of Income Data:
|
|
|
|
|
|
Net Revenues
|
$
|
205.0
|
|
|
$
|
206.3
|
|
|
$
|
190.5
|
|
Operating Income
|
138.1
|
|
|
136.1
|
|
|
128.8
|
|
Net Income
|
102.5
|
|
|
98.0
|
|
|
89.6
|
|
Balance Sheet Data:
|
|
|
|
|
|
Current Assets
|
34.8
|
|
|
35.7
|
|
|
32.1
|
|
Noncurrent Assets
|
969.8
|
|
|
987.1
|
|
|
1,016.3
|
|
Current Liabilities
|
48.0
|
|
|
44.4
|
|
|
42.6
|
|
Noncurrent Liabilities
|
497.2
|
|
|
535.8
|
|
|
568.3
|
|
Total Members’ Equity
|
459.4
|
|
|
442.6
|
|
|
437.5
|
|
Contribution/Distribution Data:
(1)
|
|
|
|
|
|
Contributions to Millennium Pipeline
|
6.2
|
|
|
1.4
|
|
|
2.6
|
|
Distribution of earnings from Millennium Pipeline
|
48.9
|
|
|
47.5
|
|
|
35.6
|
|
Hardy Storage
|
|
|
|
|
|
Statement of Income Data:
|
|
|
|
|
|
Net Revenues
|
$
|
23.5
|
|
|
$
|
23.4
|
|
|
$
|
23.6
|
|
Operating Income
|
15.7
|
|
|
15.3
|
|
|
16.1
|
|
Net Income
|
11.2
|
|
|
10.3
|
|
|
10.6
|
|
Balance Sheet Data:
|
|
|
|
|
|
Current Assets
|
10.3
|
|
|
12.1
|
|
|
12.0
|
|
Noncurrent Assets
|
151.3
|
|
|
155.5
|
|
|
157.4
|
|
Current Liabilities
|
17.2
|
|
|
19.3
|
|
|
17.1
|
|
Noncurrent Liabilities
|
57.5
|
|
|
68.5
|
|
|
77.4
|
|
Total Members’ Equity
|
86.9
|
|
|
79.8
|
|
|
74.9
|
|
Contribution/Distribution Data:
(1)
|
|
|
|
|
|
Contributions to Hardy Storage
|
—
|
|
|
—
|
|
|
—
|
|
Distribution of earnings from Hardy Storage
|
2.0
|
|
|
2.6
|
|
|
2.2
|
|
Pennant
|
|
|
|
|
|
Statement of Income Data:
|
|
|
|
|
|
Net Revenues
|
$
|
38.2
|
|
|
$
|
34.6
|
|
|
$
|
8.5
|
|
Operating Income (Loss)
|
21.2
|
|
|
17.8
|
|
|
(2.4
|
)
|
Net Income (Loss)
|
21.2
|
|
|
17.8
|
|
|
(2.4
|
)
|
Balance Sheet Data:
|
|
|
|
|
|
Current Assets
|
9.8
|
|
|
11.0
|
|
|
23.7
|
|
Noncurrent Assets
|
384.0
|
|
|
389.6
|
|
|
380.0
|
|
Current Liabilities
|
3.5
|
|
|
8.4
|
|
|
8.6
|
|
Total Members’ Equity
|
390.3
|
|
|
392.2
|
|
|
395.1
|
|
Contribution/Distribution Data:
(1)
|
|
|
|
|
|
Contributions to Pennant
|
—
|
|
|
—
|
|
|
66.6
|
|
Distribution of earnings from Pennant
|
10.6
|
|
|
7.1
|
|
|
—
|
|
Return of capital from Pennant
|
2.2
|
|
|
16.0
|
|
|
—
|
|
(1)
Contribution and distribution data represents CPG's portion based on CPG's ownership percentage of each investment.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The components of income tax expense were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Income Taxes
|
|
|
|
|
|
Current
|
|
|
|
|
|
Federal
|
$
|
(55.7
|
)
|
|
$
|
12.1
|
|
|
$
|
19.5
|
|
State
|
4.2
|
|
|
9.1
|
|
|
7.6
|
|
Total Current
|
(51.5
|
)
|
|
21.2
|
|
|
27.1
|
|
Deferred
|
|
|
|
|
|
Federal
|
116.3
|
|
|
120.2
|
|
|
119.2
|
|
State
|
13.0
|
|
|
11.6
|
|
|
23.5
|
|
Total Deferred
|
129.3
|
|
|
131.8
|
|
|
142.7
|
|
Deferred Investment Credits
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
Total Income Taxes
|
$
|
77.8
|
|
|
$
|
153.0
|
|
|
$
|
169.7
|
|
Total income taxes from continuing operations were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Book income from Continuing Operations before income taxes
|
$
|
231.5
|
|
|
|
|
$
|
460.5
|
|
|
|
|
$
|
438.4
|
|
|
|
Tax expense at statutory federal income tax rate
|
81.0
|
|
|
35.0
|
%
|
|
161.2
|
|
|
35.0
|
%
|
|
153.5
|
|
|
35.0
|
%
|
Increases (reductions) in taxes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
State income taxes, net of federal income tax benefit
|
11.2
|
|
|
4.8
|
|
|
13.4
|
|
|
2.9
|
|
|
20.3
|
|
|
4.6
|
|
Noncontrolling interest
|
(13.0
|
)
|
|
(5.6
|
)
|
|
(14.0
|
)
|
|
(3.0
|
)
|
|
—
|
|
|
—
|
|
AFUDC-Equity
|
(11.2
|
)
|
|
(4.8
|
)
|
|
(9.2
|
)
|
|
(2.0
|
)
|
|
(3.7
|
)
|
|
(0.8
|
)
|
Transaction cost
|
8.7
|
|
|
3.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other, net
|
1.1
|
|
|
0.4
|
|
|
1.6
|
|
|
0.3
|
|
|
(0.4
|
)
|
|
(0.1
|
)
|
Total Income Taxes
|
$
|
77.8
|
|
|
33.6
|
%
|
|
$
|
153.0
|
|
|
33.2
|
%
|
|
$
|
169.7
|
|
|
38.7
|
%
|
The effective income tax rates were
33.6%
,
33.2%
and
38.7%
in
2016
,
2015
and
2014
, respectively. The overall effective tax rates in 2016 and 2015 are comparable. The
5.5%
decrease in the overall effective tax rate in 2015 versus 2014 was primarily due to income received following CPPL’s IPO that is not subject to income tax at the partnership level, as well as state income taxes, utility rate making and other permanent book-to-tax differences.
On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015 (PATH). PATH, among other things, permanently extends and modifies the research credit under Internal Revenue Code Section 41, and extends bonus depreciation (additional first-year depreciation) under a phase-down through 2019, as follows:
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.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
On December 19, 2014, the President signed into law the Tax Increase Prevention Act ("TIPA"). TIPA extended and modified 50% bonus depreciation for 2014. CPG recorded the effects of TIPA in the fourth quarter 2014. In general, 50% bonus depreciation is available for property placed in service before January 1, 2015, or in the case of certain property having longer production periods, before January 1, 2016. The retroactive extension of the research credit did not have a significant effect on net income.
In March 2016, the FASB issued ASU 2016-09,
Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.
Among other provisions, the standard requires that all income tax effects of awards are recognized in the income statement when the awards vest or are settled and also allows an employer to make a policy election to account for forfeitures as they occur. CPG is required to adopt ASU 2016-09 for periods beginning after December 15, 2016, including interim periods, with early adoption permitted if all of the amendments are adopted in the same period. Each amendment has varying transition requirements. CPG expects to adopt ASU 2016-09 in the first quarter of 2017. Upon adoption, CPG will record a
$9.9 million
increase to beginning retained earnings with a corresponding increase in deferred tax assets representing the excess tax benefits generated in years prior to adoption of ASU 2016-09. Prior to the adoption of ASU 2016-09, CPG was precluded from recording this increase in deferred tax assets due to having a cumulative net operating loss carryforward for Federal income taxes.
In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of accumulated deferred income taxes on the balance sheet. ASU 2015-17 eliminated the requirement to separate deferred tax liabilities and assets into a current amount and a noncurrent amount on the balance sheet. ASU 2015-17 simplifies the presentation of ADIT by requiring ADIT liabilities and ADIT assets be classified as noncurrent on the balance sheet. The FASB decided that the amendments in ASU 2015-17 can be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The update is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016 and earlier application is permitted. CPG elected early adoption of ASU 2015-17 in December 2015. The December 31, 2016 and 2015 accumulated deferred income taxes are presented with application of ASU 2015-17, and are presented on the Consolidated Balance Sheet as a noncurrent liability.
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.
The principal components of CPG’s net deferred tax liability were as follows:
|
|
|
|
|
|
|
|
|
At December 31, (in millions)
|
2016
|
|
2015
|
Deferred tax liabilities
|
|
|
|
Accelerated depreciation and other property differences
|
$
|
1,625.8
|
|
|
$
|
1,429.2
|
|
Pension and other postretirement/postemployment benefits
|
31.1
|
|
|
29.9
|
|
Other regulatory assets
|
67.8
|
|
|
71.8
|
|
Equity method investments
|
130.2
|
|
|
124.3
|
|
Total Deferred Tax Liabilities
|
1,854.9
|
|
|
1,655.2
|
|
Deferred tax assets
|
|
|
|
Other regulatory liabilities
|
(104.9
|
)
|
|
(126.8
|
)
|
Net operating loss carryforward
|
(231.7
|
)
|
|
(141.4
|
)
|
Other
|
(17.9
|
)
|
|
(38.9
|
)
|
Total Deferred Tax Assets
|
(354.5
|
)
|
|
(307.1
|
)
|
Net Deferred Tax Liabilities
|
$
|
1,500.4
|
|
|
$
|
1,348.1
|
|
State income tax net operating loss benefits for West Virginia were recorded at their full value which CPG anticipates it is more likely than not that it will realize these benefits, prior to their expiration. The
$211.5 million
Federal net operating loss benefit carryforward will expire in various tax years from
2030
through
2036
and the
$20.2 million
state net operating loss benefit carryforward will expire in various tax years from
2028
through
2036
.
The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is
zero
for
December 31, 2016
, a
$0.4 million
decrease for
December 31, 2015
and
zero
for
December 31, 2014
. CPG recognizes accrued interest on
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
unrecognized tax benefits, accrued interest on other income tax liabilities, and tax penalties in income tax expense.
No
material amounts were recorded for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
CPG is subject to income taxation in the United States and various state jurisdictions, primarily Indiana, West Virginia, Virginia, Pennsylvania, Kentucky, Louisiana, Mississippi, Maryland, Tennessee, New Jersey and New York.
CPG was included in NiSource’s consolidated federal return prior to its separation from NiSource on July 1, 2015. Because NiSource is part of the IRS's Large and Mid-Size Business program, each year's federal income tax return is typically audited by the IRS. As of
December 31, 2016
, federal income tax years through 2015 for NiSource have been audited and are effectively closed to further assessment.
The statute of limitations in each of the state jurisdictions in which CPG operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of
December 31, 2016
, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.
Subsequent to the Merger, CPG is included in the consolidated Federal income tax return filed by US Parent and is a party to a Federal Tax Allocation Agreement with US Parent. The tax allocation agreement allocates to CPG an amount of Federal income tax liabilities and benefits similar to that which would be if CPG had filed a separate return. For states that require consolidated or combined returns, CPG will be included with certain TransCanada affiliates and will settle its state income tax liabilities and benefits with US Parent.
|
|
14.
|
Pension and Other Postretirement Benefits
|
CPG provides defined contribution plans and noncontributory defined benefit retirement plans ("the CPG Plans") that cover its employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, CPG provides health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for CPG. The expected cost of such benefits is accrued during the employees’ years of service. Current rates charged to customers of CPG include postretirement benefit costs. Cash contributions are remitted to tax-qualified trusts.
Prior to the Separation, CPG was a participant in the consolidated NiSource defined benefit retirement plans and was allocated a ratable portion of NiSource's tax-qualified trusts for the plans in which its employees and retirees participated. As a result, CPG followed multiple employer accounting under the provisions of GAAP. As of July 1, 2015, in connection with the Separation, accrued pension and postretirement benefit obligations for CPG participants and related plan assets were transferred to CPG. CPG continues to follow multiple employer accounting following the Separation.
Pension and Other Postretirement Benefit Plans’ Asset Management
. CPG employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
To establish a long-term rate of return for plan assets assumption, past historical capital market returns and a proprietary forecast are evaluated. The long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.
The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for the CPG plan assets represents a long-term view and are listed in the following table.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
In 2016, a revised asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status (as measured by the projected benefit obligation of the qualified pension plan divided by the market value of qualified pension plan assets) increases. The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on
December 31, 2016
are as follows:
Asset Mix Policy of Funds:
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plan
|
|
Postretirement Benefit Plan
|
Asset Category
|
Minimum
|
|
Maximum
|
|
Minimum
|
|
Maximum
|
Domestic Equities
|
35%
|
|
55%
|
|
35%
|
|
55%
|
International Equities
|
10%
|
|
20%
|
|
15%
|
|
25%
|
Fixed Income
|
30%
|
|
50%
|
|
20%
|
|
50%
|
Short-Term Investments
|
0%
|
|
10%
|
|
0%
|
|
10%
|
Pension Plan and Postretirement Plan Asset Mix at
December 31, 2016
and
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
Defined Benefit
Pension Plan Assets
|
|
Postretirement
Benefit Plan Assets
|
Asset Class
|
Asset Value
|
|
% of Total Assets
|
|
Asset Value
|
|
% of Total Assets
|
|
(in millions)
|
|
|
|
(in millions)
|
|
|
Domestic Equities
|
$
|
148.7
|
|
|
42.7
|
%
|
|
$
|
95.9
|
|
|
41.5
|
%
|
International Equities
|
56.3
|
|
|
16.2
|
%
|
|
43.4
|
|
|
18.8
|
%
|
Fixed Income
|
136.3
|
|
|
39.2
|
%
|
|
76.9
|
|
|
33.2
|
%
|
Cash/Other
|
6.8
|
|
|
1.9
|
%
|
|
15.1
|
|
|
6.5
|
%
|
Total
|
$
|
348.1
|
|
|
100.0
|
%
|
|
$
|
231.3
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
December 31, 2015
|
Defined Benefit
Pension Plan Assets
|
|
Postretirement
Benefit Plan Assets
|
Asset Class
|
Asset Value
|
|
% of Total Assets
|
|
Asset Value
|
|
% of Total Assets
|
|
(in millions)
|
|
|
|
(in millions)
|
|
|
Domestic Equities
|
$
|
141.0
|
|
|
39.4
|
%
|
|
$
|
101.6
|
|
|
44.4
|
%
|
International Equities
|
62.5
|
|
|
17.5
|
%
|
|
42.8
|
|
|
18.8
|
%
|
Fixed Income
|
123.3
|
|
|
34.4
|
%
|
|
76.6
|
|
|
33.6
|
%
|
Cash/Other
|
31.0
|
|
|
8.7
|
%
|
|
7.2
|
|
|
3.2
|
%
|
Total
|
$
|
357.8
|
|
|
100.0
|
%
|
|
$
|
228.2
|
|
|
100.0
|
%
|
The categorization of investments into the asset classes in the table above are based on definitions established by the CPG Benefits Committee.
Fair Value Measurements.
The following table sets forth, by level within the fair value hierarchy, the CPG Pension Plan Trust and OPEB investment assets at fair value as of
December 31, 2016
and
2015
. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total CPG Pension Plan Trust and OPEB investment assets at fair value classified within Level 3 were
zero
as of
December 31, 2016
and
December 31, 2015
.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Valuation Techniques Used to Determine Fair Value:
Level 1 Measurements
Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.
Level 2 Measurements
Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.
Level 3 Measurements
Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds' underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods.
The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days' notice. Private equity investment strategies include buy-out, venture capital, growth equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships.
Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership's fair value as recorded in the partnerships' audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds' underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation.
Net Asset Value Measurements
Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are measure at net asset value. The funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments.
For the year ended
December 31, 2016
, there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
(in millions)
|
December 31,
2016
|
|
Quoted Prices in Active
Markets for Identical Assets (Level 1)
|
|
Significant Other
Observable Inputs (Level 2)
|
|
Significant
Unobservable Inputs (Level 3)
|
Pension plan assets
|
|
|
|
|
|
|
|
Cash
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fixed income securities
|
|
|
|
|
|
|
|
Government
|
8.8
|
|
|
—
|
|
|
8.8
|
|
|
—
|
|
Corporate
|
19.5
|
|
|
—
|
|
|
19.5
|
|
|
—
|
|
Commingled funds
|
|
|
|
|
|
|
|
Short-term money markets
(2)
|
6.6
|
|
|
|
|
|
|
|
|
|
|
U.S. equities
(2)
|
93.1
|
|
|
|
|
|
|
|
|
|
|
International equities
(2)
|
56.3
|
|
|
|
|
|
|
|
|
|
|
Fixed income
(2)
|
73.2
|
|
|
|
|
|
|
|
|
|
Mutual funds
|
|
|
|
|
|
|
|
U.S. equities
|
55.6
|
|
|
55.6
|
|
|
—
|
|
|
—
|
|
Fixed income
|
34.8
|
|
|
34.8
|
|
|
—
|
|
|
—
|
|
Pension plan assets subtotal
|
348.1
|
|
|
90.6
|
|
|
28.3
|
|
|
—
|
|
Other postretirement benefit plan assets
|
|
|
|
|
|
|
|
Cash
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
Commingled funds
|
|
|
|
|
|
|
|
Short-term money markets
(2)
|
14.7
|
|
|
|
|
|
|
|
|
|
|
U.S. equities
(2)
|
1.0
|
|
|
|
|
|
|
|
|
|
|
Mutual funds
|
|
|
|
|
|
|
|
U.S. equities
|
94.9
|
|
|
94.9
|
|
|
—
|
|
|
—
|
|
International equities
|
43.4
|
|
|
43.4
|
|
|
—
|
|
|
—
|
|
Fixed income
|
76.9
|
|
|
76.9
|
|
|
—
|
|
|
—
|
|
Other postretirement benefit plan assets subtotal
|
231.3
|
|
|
215.6
|
|
|
—
|
|
|
—
|
|
Due to brokers, net
(1)
|
(0.2
|
)
|
|
|
|
|
|
|
Accrued investment income/dividends
|
0.6
|
|
|
|
|
|
|
|
Total pension and other postretirement benefit plan assets
|
$
|
579.8
|
|
|
$
|
306.2
|
|
|
$
|
28.3
|
|
|
$
|
—
|
|
(1)
This class represents pending trades with brokers.
(2)
This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Fair Value
|
|
Unfunded Commitments
|
|
Redemption Frequency
|
|
Redemption Notice Period
|
Commingled Funds
|
|
|
|
|
|
|
|
Short-term money markets
|
$
|
21.3
|
|
|
$
|
—
|
|
|
Daily
|
|
1 day
|
U.S. equities
|
94.1
|
|
|
—
|
|
|
Daily
|
|
1 day
|
International equities
|
56.3
|
|
|
—
|
|
|
Daily
|
|
2 days
|
Fixed income
|
73.2
|
|
|
—
|
|
|
Daily
|
|
2-3 days
|
Total
|
$
|
244.9
|
|
|
—
|
|
|
|
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Fair Value Measurements at
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
(in millions)
|
December 31,
2015
|
|
Quoted Prices in Active
Markets for Identical Assets (Level 1)
|
|
Significant Other
Observable Inputs (Level 2)
|
|
Significant
Unobservable Inputs (Level 3)
|
Pension plan assets
|
|
|
|
|
|
|
|
Cash
|
$
|
0.9
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity securities
|
|
|
|
|
|
|
|
International equities
|
6.6
|
|
|
6.6
|
|
|
—
|
|
|
—
|
|
Fixed income securities
|
|
|
|
|
|
|
|
Government
|
8.5
|
|
|
—
|
|
|
8.5
|
|
|
—
|
|
Corporate
|
13.0
|
|
|
—
|
|
|
13.0
|
|
|
—
|
|
Commingled funds
|
|
|
|
|
|
|
|
Short-term money markets
(2)
|
31.1
|
|
|
|
|
|
|
|
|
|
|
U.S. equities
(2)
|
141.0
|
|
|
|
|
|
|
|
|
|
|
International equities
(2)
|
55.6
|
|
|
|
|
|
|
|
|
|
|
Fixed income
(2)
|
100.9
|
|
|
|
|
|
|
|
|
|
|
Pension plan assets subtotal
|
357.6
|
|
|
7.5
|
|
|
21.5
|
|
|
—
|
|
Other postretirement benefit plan assets
|
|
|
|
|
|
|
|
Commingled funds
|
|
|
|
|
|
|
|
Short-term money markets
(2)
|
7.3
|
|
|
|
|
|
|
|
|
|
|
U.S. equities
(2)
|
13.9
|
|
|
|
|
|
|
|
|
|
|
Mutual funds
|
|
|
|
|
|
|
|
U.S. equities
|
87.7
|
|
|
87.7
|
|
|
—
|
|
|
—
|
|
International equities
|
42.8
|
|
|
42.8
|
|
|
—
|
|
|
—
|
|
Fixed income
|
76.5
|
|
|
76.5
|
|
|
—
|
|
|
—
|
|
Other postretirement benefit plan assets subtotal
|
228.2
|
|
|
207.0
|
|
|
—
|
|
|
—
|
|
Due to brokers, net
(1)
|
(0.4
|
)
|
|
|
|
|
|
|
Accrued investment income/dividends
|
0.6
|
|
|
|
|
|
|
|
Total pension and other postretirement benefit plan assets
|
$
|
586.0
|
|
|
$
|
214.5
|
|
|
$
|
21.5
|
|
|
$
|
—
|
|
(1)
This class represents pending trades with brokers.
(2)
This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Balance at
January 1, 2015
|
|
Total gains or
losses (unrealized
/ realized)
|
|
Purchases
|
|
(Sales)
|
|
Transfers
into/(out of)
level 3
|
|
Separation Allocation
(1)
|
|
Balance at
December 31,
2015
|
Fixed income securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other fixed income
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.1
|
)
|
|
$
|
—
|
|
Private equity limited partnerships
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. multi-strategy
|
8.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8.5
|
)
|
|
—
|
|
International multi-strategy
|
5.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5.3
|
)
|
|
—
|
|
Distressed opportunities
|
1.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.1
|
)
|
|
—
|
|
Real estate
|
2.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.6
|
)
|
|
—
|
|
Total
|
$
|
17.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(17.6
|
)
|
|
$
|
—
|
|
(1)
Level 3 assets were not contributed to the CPG Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Fair Value
|
|
Unfunded Commitments
|
|
Redemption Frequency
|
|
Redemption Notice Period
|
Commingled Funds
|
|
|
|
|
|
|
|
Short-term money markets
|
$
|
38.4
|
|
|
$
|
—
|
|
|
Daily
|
|
1 day
|
U.S. equities
|
154.9
|
|
|
—
|
|
|
Monthly
|
|
3 days
|
International equities
|
55.6
|
|
|
—
|
|
|
Monthly
|
|
14-30 days
|
Fixed income
|
100.9
|
|
|
—
|
|
|
Monthly
|
|
3 days
|
Total
|
$
|
349.8
|
|
|
$
|
—
|
|
|
|
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure
. The following table provides a reconciliation of the plans’ funded status and amounts reflected in CPG’s Consolidated Balance Sheets at December 31 based on a December 31 measurement date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Change in projected benefit obligation
(1)
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
$
|
404.5
|
|
|
$
|
397.6
|
|
|
$
|
112.1
|
|
|
$
|
124.2
|
|
Service cost
|
6.4
|
|
|
5.9
|
|
|
0.9
|
|
|
1.0
|
|
Interest cost
|
15.1
|
|
|
15.0
|
|
|
4.5
|
|
|
4.7
|
|
Plan participants’ contributions
|
—
|
|
|
—
|
|
|
2.8
|
|
|
2.3
|
|
Actuarial (gain) loss
|
(4.7
|
)
|
|
(6.9
|
)
|
|
2.1
|
|
|
(12.4
|
)
|
Settlement loss
|
3.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefits paid
|
(48.8
|
)
|
|
(29.7
|
)
|
|
(13.6
|
)
|
|
(9.8
|
)
|
Estimated benefits paid by incurred subsidy
|
—
|
|
|
—
|
|
|
0.3
|
|
|
0.3
|
|
Transfer of participant balances from NiSource plans
(2)
|
—
|
|
|
22.6
|
|
|
—
|
|
|
1.8
|
|
Projected benefit obligation at end of year
|
$
|
375.7
|
|
|
$
|
404.5
|
|
|
$
|
109.1
|
|
|
$
|
112.1
|
|
Change in plan assets
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
$
|
357.8
|
|
|
$
|
351.0
|
|
|
$
|
228.2
|
|
|
$
|
223.8
|
|
Actual return on plan assets
|
30.7
|
|
|
1.2
|
|
|
13.6
|
|
|
(2.5
|
)
|
Employer contributions
|
8.4
|
|
|
20.0
|
|
|
0.3
|
|
|
13.5
|
|
Plan participants’ contributions
|
—
|
|
|
—
|
|
|
2.8
|
|
|
2.3
|
|
Benefits paid
|
(48.8
|
)
|
|
(29.7
|
)
|
|
(13.6
|
)
|
|
(9.8
|
)
|
Transfer of participant balances from NiSource plans
(2)
|
—
|
|
|
15.3
|
|
|
—
|
|
|
0.9
|
|
Fair value of plan assets at end of year
|
$
|
348.1
|
|
|
$
|
357.8
|
|
|
$
|
231.3
|
|
|
$
|
228.2
|
|
Funded status at end of year
|
$
|
(27.6
|
)
|
|
$
|
(46.7
|
)
|
|
$
|
122.2
|
|
|
$
|
116.1
|
|
Amounts recognized in the balance sheet consist of:
|
|
|
|
|
|
|
|
Noncurrent assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
122.2
|
|
|
$
|
116.1
|
|
Current liabilities
|
—
|
|
|
(0.8
|
)
|
|
—
|
|
|
—
|
|
Noncurrent liabilities
|
(27.6
|
)
|
|
(45.9
|
)
|
|
—
|
|
|
—
|
|
Net amount recognized at end of year
(3)
|
$
|
(27.6
|
)
|
|
$
|
(46.7
|
)
|
|
$
|
122.2
|
|
|
$
|
116.1
|
|
Amounts recognized in AOCI or regulatory assets/liabilities
(4)
|
|
|
|
|
|
|
|
Unrecognized prior service credit
|
$
|
(2.6
|
)
|
|
$
|
(3.7
|
)
|
|
$
|
(1.3
|
)
|
|
$
|
(2.0
|
)
|
Unrecognized actuarial loss (gain)
|
133.0
|
|
|
164.5
|
|
|
(0.7
|
)
|
|
(3.9
|
)
|
Total recognized AOCI or regulatory assets/liabilities
|
$
|
130.4
|
|
|
$
|
160.8
|
|
|
$
|
(2.0
|
)
|
|
$
|
(5.9
|
)
|
(1)
The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.
(2)
Reflects the transfer of additional pension and OPEB plan participants to CPGSC upon Separation from NiSource that were determined in the current year.
(3)
CPG recognizes in its Consolidated Balance Sheets the underfunded and overfunded status of its various defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(4)
CPG determined that the future recovery of pension and other postretirement benefits costs is probable. CPG recorded regulatory assets and liabilities of
$111.3 million
and
zero
, respectively, as of
December 31, 2016
, and
$135.2 million
and
$0.7 million
, respectively, as of
December 31, 2015
that would otherwise have been recorded to accumulated other comprehensive loss.
CPG’s accumulated benefit obligation for its pension plans was
$375.7 million
and
$404.5 million
as of
December 31, 2016
and
2015
, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels.
CPG's pension plans were underfunded by
$27.6 million
at
December 31, 2016
, compared to being underfunded by
$46.7 million
at
December 31, 2015
. The improvement in funded status is primarily due to the return on plan assets. CPG contributed
$8.4 million
and
$20.0 million
to its pension plans in
2016
and
2015
, respectively.
During
2016
, CPG’s funded status for its other postretirement benefit plans improved by
$6.1 million
to an overfunded status of
$122.2 million
primarily due to the return on plan assets, offset by a decrease in the discount rates in 2016 compared to 2015. CPG
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
contributed approximately
$0.3 million
and
$13.5 million
to its other postretirement benefit plans in
2016
and
2015
, respectively. No amounts of CPG’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG or any of its subsidiaries in
2017
.
In 2016, CPG's pension plans had year to date lump sum payouts exceeding the plans' 2016 service cost plus interest cost due to Merger related payouts as well as the non-qualified pension plan being terminated in connection with the Merger. As a result, settlement accounting was required and CPG recorded a settlement charge of
$12.3 million
for the year ended December 31, 2016.
The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for CPG’s various plans as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Weighted-average assumptions to Determine Benefit Obligation
|
|
|
|
|
|
|
|
Discount Rate
|
4.10
|
%
|
|
4.05
|
%
|
|
4.25
|
%
|
|
4.29
|
%
|
Rate of Compensation Increases
|
2.50
|
%
|
|
4.00
|
%
|
|
|
|
|
Health Care Trend Rates
|
|
|
|
|
|
|
|
Trend for Next Year
|
|
|
|
|
8.47
|
%
|
|
8.39
|
%
|
Ultimate Trend
|
|
|
|
|
4.50
|
%
|
|
4.50
|
%
|
Year Ultimate Trend Reached
|
|
|
|
|
2024
|
|
|
2022
|
|
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
|
|
|
|
|
|
|
|
(in millions)
|
1% point increase
|
|
1% point decrease
|
Effect on service and interest components of net periodic cost
|
$
|
0.1
|
|
|
$
|
(0.1
|
)
|
Effect on accumulated postretirement benefit obligation
|
2.6
|
|
|
(2.4
|
)
|
CPG expects to make contributions of
zero
dollars to its pension plan and approximately
$1.9 million
to its postretirement medical and life plans in
2017
.
The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure CPG's benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
|
Federal
Subsidy Receipts
|
Year(s)
|
|
|
|
|
|
2017
|
$
|
32.3
|
|
|
$
|
7.8
|
|
|
$
|
0.5
|
|
2018
|
33.1
|
|
|
7.8
|
|
|
0.5
|
|
2019
|
33.8
|
|
|
7.8
|
|
|
0.4
|
|
2020
|
35.2
|
|
|
7.7
|
|
|
0.4
|
|
2021
|
34.9
|
|
|
7.6
|
|
|
0.4
|
|
2022-2026
|
168.8
|
|
|
35.5
|
|
|
1.2
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
(in millions)
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
Components of Net Periodic Benefit Cost (Income)
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
6.4
|
|
|
$
|
5.9
|
|
|
$
|
4.8
|
|
|
$
|
0.9
|
|
|
$
|
1.0
|
|
|
$
|
1.1
|
|
Interest cost
|
15.1
|
|
|
15.0
|
|
|
15.7
|
|
|
4.5
|
|
|
4.7
|
|
|
4.6
|
|
Expected return on assets
|
(25.0
|
)
|
|
(28.2
|
)
|
|
(27.3
|
)
|
|
(15.0
|
)
|
|
(18.1
|
)
|
|
(16.6
|
)
|
Amortization of prior service (credit) cost
|
(1.2
|
)
|
|
(1.1
|
)
|
|
(1.1
|
)
|
|
(0.7
|
)
|
|
(0.3
|
)
|
|
0.1
|
|
Recognized actuarial loss (gain)
|
12.2
|
|
|
9.9
|
|
|
7.5
|
|
|
0.3
|
|
|
(0.3
|
)
|
|
—
|
|
Net Periodic Benefit Cost (Income)
|
7.5
|
|
|
1.5
|
|
|
(0.4
|
)
|
|
(10.0
|
)
|
|
(13.0
|
)
|
|
(10.8
|
)
|
Additional loss recognized due to:
|
|
|
|
|
|
|
|
|
|
|
|
Settlement loss
|
12.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Net Periodic Benefit Cost (Income)
|
$
|
19.8
|
|
|
$
|
1.5
|
|
|
$
|
(0.4
|
)
|
|
$
|
(10.0
|
)
|
|
$
|
(13.0
|
)
|
|
$
|
(10.8
|
)
|
The
$18.3 million
increase
in the actuarially-determined pension benefit cost (income) is due primarily to the settlement charge and a decrease in the expected return on plan assets in
2016
compared to
2015
. For its other postretirement benefit plans, CPG recognized
$10.0 million
in net periodic benefit income in
2016
compared to net periodic benefit income of
$13.0 million
in
2015
due primarily to a decrease in the expected return on plan assets in
2016
compared to
2015
.
The following table provides the key assumptions that were used to calculate the net periodic benefits cost for CPG's various plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
Weighted-average Assumptions to Determine Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
3.90
|
%
|
|
3.84
|
%
|
|
4.34
|
%
|
|
4.12
|
%
|
|
4.10
|
%
|
|
4.76
|
%
|
Expected Long-Term Rate of Return on Plan Assets
|
7.29
|
%
|
|
8.20
|
%
|
|
8.30
|
%
|
|
6.81
|
%
|
|
8.05
|
%
|
|
8.14
|
%
|
Rate of Compensation Increases
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
|
|
|
|
|
CPG believes it is appropriate to assume an
7.29%
and
6.81%
rate of return on pension and other postretirement plan assets, respectively, for its calculation of
2016
pension benefits cost. This is primarily based on asset mix and historical rates of return.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
(in millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory assets or liabilities
|
|
|
|
|
|
|
|
Settlements
|
$
|
(12.3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net actuarial (gain) loss
|
(7.1
|
)
|
|
25.6
|
|
|
3.5
|
|
|
8.6
|
|
Less: amortization of prior service cost
|
1.2
|
|
|
1.1
|
|
|
0.7
|
|
|
0.3
|
|
Less: amortization of net actuarial (gain) loss
|
(12.2
|
)
|
|
(9.9
|
)
|
|
(0.3
|
)
|
|
0.3
|
|
Total recognized in other comprehensive income or regulatory assets or liabilities
|
$
|
(30.4
|
)
|
|
$
|
16.8
|
|
|
$
|
3.9
|
|
|
$
|
9.2
|
|
Amount recognized in net periodic benefit cost and other comprehensive income or regulatory assets or liabilities
|
$
|
(10.6
|
)
|
|
$
|
18.3
|
|
|
$
|
(6.1
|
)
|
|
$
|
(3.8
|
)
|
Based on a December 31, 2016 measurement date, the net unrecognized actuarial (gain) loss, unrecognized prior service cost, and unrecognized transition obligation that will be amortized into net periodic benefit cost during
2017
for the pension plans are
$10.0 million
,
$(1.2) million
and
zero
, respectively, and for other postretirement benefit plans are
$0.5 million
,
$(0.7) million
and
zero
, respectively.
CPG has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits, short-term borrowings and short-term borrowings-affiliated. CPG’s long-term debt is recorded at historical amounts.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Long-term debt
. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended
December 31, 2016
and
2015
, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.
The carrying amount and estimated fair values of financial instruments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
(in millions)
|
Carrying
Amount
2016
(1)
|
|
Estimated
Fair Value
2016
|
|
Carrying
Amount
2015
(1)
|
|
Estimated
Fair Value
2015
|
Long-term debt
|
$
|
2,750.0
|
|
|
$
|
2,868.8
|
|
|
$
|
2,750.0
|
|
|
$
|
2,592.1
|
|
(1)
The carrying amount of the Notes differs from the Long-term debt balance on the Consolidated Balance Sheets due to the related unamortized discount and unamortized debt issuance costs, both of which are being amortized over the weighted average life of the Notes.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
|
|
16.
|
Share-Based Compensation
|
Prior to the Separation, CPG employees participated in NiSource's Omnibus Incentive Plan (the "NiSource Plan") and had outstanding awards under the NiSource Director Stock Incentive Plan (“NiSource Director Plan”), which was terminated in 2010. Upon the Separation, outstanding CPG employee restricted stock units, performance units and employee director awards previously issued under the NiSource Plan and NiSource Director Plan were adjusted and converted into new CPG share-based awards under the Columbia Pipeline Group, Inc. 2015 Omnibus Incentive Plan (the "Omnibus Plan") using a formula designed to preserve the intrinsic value and fair value of the awards immediately prior to the Separation. The performance targets applicable to the performance units were frozen at the levels achieved as of the Separation and pro-rated to reflect the proportion of the service period completed. Under the Omnibus Plan, these awards represent restricted stock units with no performance contingencies. All adjusted awards retained the vesting schedule of the original awards.
The Omnibus Plan term began on the effective date of the Separation. The Omnibus Plan provided for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock and restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards.
On July 1, 2016, at the effective time of the Merger, each outstanding restricted stock unit, performance share and phantom unit, whether or not vested, was deemed to be fully vested (in the case of performance shares, based on performance deemed satisfied at the greater of actual performance for the relevant period and the target level of 100%), canceled and converted into the right of the holder to receive
$25.50
in cash, without interest, in respect of each share of CPG common stock underlying such award.
CPG recognized stock-based employee compensation expense of
$65.2 million
,
$7.9 million
and
$4.4 million
, during the years ended
December 31, 2016
,
2015
and
2014
, respectively, as well as related tax benefits of
$21.9 million
,
$2.9 million
and
$1.6 million
, respectively.
Restricted Stock Units and Restricted Stock
. In
2016
, CPG granted
12,144
restricted stock units and shares of restricted stock, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was
$0.2 million
, based on the average market price of CPG's common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period which is generally
three
years. There are
no
restricted stock units or shares of restricted stock outstanding for the 2016 award following the effective time of the Merger.
In 2015, CPG granted
130,160
restricted stock units and shares of restricted stock, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was
$3.6 million
, based on the average market price of CPG’s common stock at the date of each grant less the present value of any dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period which is generally
three
years. There are
no
restricted stock units or shares of restricted stock outstanding for the 2015 award following the effective time of the Merger.
In 2015, NiSource granted restricted stock units and shares of restricted stock that were converted into
450,107
CPG restricted stock units at Separation, subject to service conditions. The total grant date fair value of the shares of restricted stock units and shares of restricted stock was
$11.6 million
, based on the average market price of NiSource’s common stock at the date of each grant less the present value of any dividends not received during the vesting period converted into CPG common stock awards, which will be expensed, net of forfeitures, over the vesting period which is generally
three
years. There are
no
restricted stock units or shares of restricted stock outstanding for the 2015 NiSource award following the effective time of the Merger.
In 2014, NiSource granted restricted stock units and shares of restricted stock that were converted into
198,532
CPG restricted stock units at Separation, subject to service conditions. The total grant date fair value of the restricted stock units and shares of restricted stock was
$4.2 million
, based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period converted into CPG common stock awards, which will be expensed, net of forfeitures, over the vesting period which is generally
three
years. There are
no
restricted stock units or shares of restricted stock outstanding for the 2014 NiSource award following the effective time of the Merger.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
|
|
|
|
|
|
|
|
|
Restricted Stock
Units
|
|
Weighted Average
Grant Date Fair
Value
|
Nonvested at December 31, 2015
|
2,268,792
|
|
|
$
|
18.85
|
|
Granted
|
12,144
|
|
|
16.86
|
|
Forfeited
|
(22,590
|
)
|
|
22.71
|
|
Vested
|
(2,258,346
|
)
|
|
18.80
|
|
Outstanding at December 31, 2016
|
—
|
|
|
$
|
—
|
|
Performance Shares
. In
2016
, CPG granted
955,848
performance shares subject to performance and service conditions. The grant date fair value of the awards was
$17.0 million
, based on the average market price of CPG's common stock at the date of grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. There are
no
performance shares outstanding for the
2016
award following the effective time of the Merger.
In 2015, CPG granted
161,504
performance shares subject to performance and service conditions. The grant date fair value of the awards was
$4.5 million
, based on the average market price of CPG’s common stock at the date of the grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. There are
no
performance shares outstanding for the 2015 award following the effective time of the Merger.
In 2014, NiSource granted performance shares that were converted to
586,219
CPG restricted stock units at Separation, subject to performance and service conditions. The grant date fair value of the awards was
$11.3 million
, based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting period which will be expensed, net of forfeitures, over the three year requisite service period. Through the conversion, the performance contingencies were removed from these awards. There are
no
restricted stock units or shares of restricted stock outstanding for the 2014 NiSource award following the effective time of the Merger.
|
|
|
|
|
|
|
|
|
Contingent
Awards
|
|
Weighted Average
Grant Date Fair
Value
|
Nonvested at December 31, 2015
|
161,504
|
|
|
$
|
28.16
|
|
Granted
|
955,848
|
|
|
17.79
|
|
Forfeited
|
—
|
|
|
—
|
|
Vested
|
(1,117,352
|
)
|
|
19.29
|
|
Outstanding at December 31, 2016
|
—
|
|
|
$
|
—
|
|
Non-employee Director Awards
. Restricted stock units were granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s restricted stock units would vest on the first anniversary of the grant thereof, subject to special pro-rata vesting rules in the event of Retirement or Disability (as defined in the award agreement), or death. The vested restricted stock units were payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. There are
no
units outstanding following the effective time of the Merger.
Fully vested restricted stock units that remained outstanding under the NiSource Plan and NiSource Director Plan as of the Separation date were converted into CPG awards. All such awards were distributed to the directors upon their separation from CPG's board of directors. There are
no
restricted stock units outstanding following the effective time of the Merger.
401(k) Match, Profit Sharing and Company Contribution.
CPG has a voluntary 401(k) savings plan covering eligible employees that allows for periodic discretionary matches as a percentage of each participant's contributions. CPG also has a retirement savings plan that provides for discretionary profit sharing contributions to eligible employees based on earnings results; and eligible exempt employees hired after January 1, 2013, receive a non-elective company contribution of three percent of eligible pay. For the years ended
December 31, 2016
,
2015
and
2014
, CPG recognized 401(k) match, profit sharing and non-elective contribution expense of
$12.2 million
,
$9.8 million
and
$8.4 million
, respectively.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
17.
Other Commitments and Contingencies
A.
Guarantees and Indemnities.
In the normal course of business, CPG and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a parent or subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the parent or subsidiaries' intended commercial purposes. The total guarantees and indemnities in existence at
December 31, 2016
and the years in which they expire were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Total
|
2017
|
2018
|
2019
|
2020
|
2021
|
After
|
Other guarantees
|
$
|
4.7
|
|
$
|
2.2
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
2.5
|
|
Guarantees of Debt.
Certain of CPG's subsidiaries, including OpCo GP, Columbia OpCo and CEG have guaranteed payment of
$2,750.0 million
in aggregated principal amount of CPG's senior notes. Each guarantor of CPG's obligations is required to comply with covenants under the debt indenture and in the event of default the guarantors would be obligated to pay the debt's principal and related interest.
Lines and Letters of Credit.
CPG maintained a
$1,500.0 million
senior revolving credit facility, of which
$250.0 million
in letters of credit was available. On July 1, 2016, in connection with the Merger, all existing letters of credit were migrated to a TransCanada credit facility and the CPG revolving credit facility was terminated. CPPL maintained a
$500.0 million
senior revolving credit facility, of which
$50.0 million
was available for issuance of letters of credit. On June 29, 2016, in anticipation of the Merger, all outstanding borrowings, facility fees and interest were paid in full and the revolving credit facility was terminated.
CPG's commercial paper program (the "Program") had a Progra
m limit of up to
$1,000.0 million
. CEG, OpCo GP and Columbia OpCo each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the promissory notes. On June 30, 2016, in anticipation of the Merger, the Program was terminated. CPG had
no
promissory notes outstanding under the Program at the time of termination.
CPG maintains a
$1,000.0 million
revolving credit facility. CPG expects that the revolving credit facility will be utilized for the financing of capital expenditures and for CPG’s general corporate purposes, including working capital. As of December 31, 2016, CPG had
no
outstanding borrowings under the revolving credit facility.
Other Guarantees or Obligations.
CPG has purchase and sale agreement guarantees totaling
$4.7 million
, which guarantee purchaser performance or seller performance under covenants, obligations, liabilities, representations or warranties under the agreements. No amounts related to the purchase and sale agreement guarantees are reflected in the Consolidated Balance Sheets. Management believes that the likelihood CPG would be required to perform or otherwise incur any significant losses associated with any of the aforementioned guarantees is remote.
Other Legal Proceedings
. In the normal course of its business, CPG has been named as a defendant in various legal proceedings. In the opinion of CPG, the ultimate disposition of these currently asserted claims will not have a material impact on CPG's consolidated financial statements.
B.
Tax Matters
. CPG records liabilities for potential income tax assessments. The accruals relate to tax positions in a variety of taxing jurisdictions and are based on CPG’s estimate of the ultimate resolution of these positions. These liabilities may be affected by changing interpretations of laws, rulings by tax authorities, or the expiration of the statute of limitations. CPG was included in NiSource's consolidated federal return for tax years prior to December 31, 2014 and will be included in NiSource's consolidated 2015 federal return through July 1, 2015. NiSource is part of the IRS Large and Mid-Size Business program. As a result, each year’s federal income tax return is typically audited by the IRS. As of December 31, 2016, federal income tax years through 2015 for NiSource have been audited and are effectively closed to further assessment. The statute of limitations in each of the state jurisdictions in which CPG operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2016, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.
CPG is currently being audited for sales and use tax compliance in the state of Ohio and West Virginia. None of these sales and use tax audits are expected to have a material impact on the consolidated and combined financial statements.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
C.
Environmental Matters
.
CPG’s operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and nonhazardous waste. Historically, CPG’s environmental compliance costs have not had a material adverse effect on its results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on CPG’s business and operating results.
It is CPG’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that CPG will not incur fines and penalties.
As of
December 31, 2016
and
2015
, CPG has liabilities recorded of approximately
$7.8 million
and
$8.3 million
, respectively, to cover environmental remediation at various sites. The current portion of these liabilities is included in “Other accruals” in the Consolidated Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated Balance Sheets. CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. As of the date of these financial statements, these expenditures are not estimable at some sites. CPG periodically adjusts its accrual as information is collected and estimates become more refined.
Air
The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. The actions listed below could require further reductions in emissions from various emission sources. CPG will continue to closely monitor developments in these matters.
National Ambient Air Quality Standards
.
The federal CAA requires the EPA to set NAAQS for particulate matter and five other pollutants considered harmful to public health and the environment. Periodically, the EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by gas transmission operations.
Climate Change.
The EPA has already promulgated regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the United States on an annual basis. In August 2016, the EPA proposed a rule revising provisions of the Prevention of Significant Deterioration ("PSD") and Title V Permitting Regulations to conform with the U.S. Supreme Court’s decision in UARG v. EPA, 134 S. Ct. 2427 (2014), and the amended judgment issued by the D.C. Circuit, in Coalition for Responsible Regulation v. EPA, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015). For instance, the August 2016 proposed rule seeks to ensure that neither the PSD nor the Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit ("PTE") GHGs above the applicable regulatory thresholds. In addition, EPA is also proposing under the rulemaking a significant emissions rate ("SER") of
75,000
tons per year carbon dioxide equivalent for GHGs under the PSD program that would establish an appropriate threshold level below which Best Available Control Technology ("BACT") is not required for a source’s GHG emissions. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.
New Source Performance Standards
: In August 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. In May 2016, the EPA finalized the rule to regulate fugitive methane emissions in the natural gas transmission and storage
sector. The final rule was subsequently published in the Federal Register on June 3, 2016. CPG is working with industry groups to litigate the delay of repair criteria in the Final Rule and to clarify ambiguities within the rule. Currently, CPG's facilit
ies are not impacted by this rule. New or modified sources installed in subsequent years will be impacted by this rule at a cost of approximately
$30,000
/site/year. Based on the current capital project schedule, 16 new or modified facilities will be impacted by this rule in 2019 at a total estimated cost of
$500,000
annually thereafter.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Environmental Remediation
CPG has liabilities associated with the cleanup of some of its former operations.
Four
sites are associated with its former propane operations and
ten
sites associated with former petroleum operations. The total liability related to these sites was
$6.3 million
and
$6.5 million
at
December 31, 2016
and
2015
, respectively. The liability represents CPG’s best estimate of the cost to remediate the facilities.
CPG has liabilities associated with the PCB remediation of its existing facilities. The total liability related to these sites was
$1.5 million
and
$1.8 million
at
December 31, 2016
and
2015
, respectively. The liability represents CPG's best estimate of the cost to remediate the facilities.
Pipeline Safety
In March 2016, the PHMSA announced a proposed rulemaking that would, if adopted, impose more stringent requirements for certain gas lines and gathering lines under varying circumstances. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond “high consequence areas” to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as
5
dwellings within the potential impact area; require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require gathering lines in Class I areas, both onshore and offshore, to comply with standards regarding damage prevention, corrosion control (for metallic pipe), public education, MAOP limits, line markers and emergency planning if such gathering lines’ nominal design is
8
inches or more. In order to provide clarity and greater certainty on what may constitute a “gathering line,” PHMSA is proposing a new definition of that term under the rulemaking, which term would now encompass “a pipeline, or a connected series of pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of the following endpoints” including the “inlet of 1
st
gas processing plant;” the “outlet of” a gas treatment facility (not associated with a processing plant or compressor station); the “[o]utlet of the furthermost downstream compressor” leading to a pipeline, or the “point where separate production fields are commingled.” Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.
On June 22, 2016, President Obama signed the 2016 Pipeline Safety Act. Extending PHMSA’s statutory mandate through 2019, the 2016 Pipeline Safety Act establishes or continues the development of stringent requirements affecting pipeline safety. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.
PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe natural gas and hazardous liquid pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. This new rule allows PHMSA to impose restrictions, prohibitions, and require safety measures without giving operators prior notice or an opportunity for a hearing. In contrast to PHMSA’s past practice of issuing Corrective Action Orders to an individual owner, operator, or facility, under the new rule PHMSA can issue an Emergency Order for numerous entities. PHMSA has until March 19, 2017 to issue a permanent final rule, when this temporary rule expires. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.
D.
Operating Lease Commitments.
CPG leases assets in several areas of its operations. Payments made in connection with operating leases were
$23.9 million
in
2016
,
$21.2 million
in
2015
and
$14.9 million
in
2014
, and are primarily charged to operation and maintenance expense as incurred.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Future minimum rental payments required under operating and capital leases that have initial or remaining non-cancelable lease terms in excess of one year are:
|
|
|
|
|
(in millions)
|
Operating
Leases
(1)
|
2017
|
$
|
8.7
|
|
2018
|
7.4
|
|
2019
|
6.6
|
|
2020
|
6.3
|
|
2021
|
5.5
|
|
After
|
23.5
|
|
Total future minimum payments
|
$
|
58.0
|
|
(1)
Operating lease expense includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.
E.
Service Obligations
. CPG has entered into various service agreements whereby CPG is contractually obligated to make certain minimum payments in future periods. CPG has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2017 to 2031, require CPG to pay fixed monthly charges.
On
June 15, 2015
, CPG entered into a five-year IT services agreement including cloud, mobile, analytics and security technologies with IBM. The agreement became effective with the closing of the Separation on
July 1, 2015
, with tiered commencement dates by service line. Under the agreement, at December 31, 2016, CPG expects to pay approximately
$128.2 million
to IBM in service fees as shown in the table below. Upon any termination of the agreement by CPG for any reason (other than material breach by IBM), CPG may be required to pay IBM a termination charge that could include a breakage fee, repayment of IBM's capital investments not yet recovered and IBM's wind-down expense. This termination fee could be material depending on the events giving rise to the termination and the timing of the termination.
The estimated aggregate amounts of minimum fixed payments at
December 31, 2016
, were:
|
|
|
|
|
|
|
|
|
(in millions)
|
Pipeline
Service
Agreements
|
|
IBM Service Agreement
|
2017
|
$
|
67.0
|
|
|
$
|
34.3
|
|
2018
|
63.4
|
|
|
31.8
|
|
2019
|
55.9
|
|
|
31.2
|
|
2020
|
38.4
|
|
|
30.9
|
|
2021
|
32.2
|
|
|
—
|
|
After
|
187.0
|
|
|
—
|
|
Total future minimum payments
|
$
|
443.9
|
|
|
$
|
128.2
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
18.
Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Gains and Losses on Cash Flow Hedges
(1)
|
|
Pension and OPEB Items
(1)
|
|
Accumulated
Other
Comprehensive
Loss
(1)
|
Balance as of January 1, 2014 -
Predecessor
|
$
|
(17.6
|
)
|
|
$
|
(8.2
|
)
|
|
$
|
(25.8
|
)
|
Other comprehensive income before reclassifications
|
—
|
|
|
(9.3
|
)
|
|
(9.3
|
)
|
Amounts reclassified from accumulated other comprehensive income
|
1.0
|
|
|
(0.4
|
)
|
|
0.6
|
|
Net current-period other comprehensive income
|
1.0
|
|
|
(9.7
|
)
|
|
(8.7
|
)
|
Balance as of December 31, 2014
|
$
|
(16.6
|
)
|
|
$
|
(17.9
|
)
|
|
$
|
(34.5
|
)
|
Other comprehensive income before reclassifications
|
(0.9
|
)
|
|
5.0
|
|
|
4.1
|
|
Amounts reclassified from accumulated other comprehensive income
(2)
|
1.1
|
|
|
0.2
|
|
|
1.3
|
|
Net current-period other comprehensive income
|
0.2
|
|
|
5.2
|
|
|
5.4
|
|
Allocation of accumulated other comprehensive loss to noncontrolling interest
|
2.1
|
|
|
—
|
|
|
2.1
|
|
Balance as of December 31, 2015
|
$
|
(14.3
|
)
|
|
$
|
(12.7
|
)
|
|
$
|
(27.0
|
)
|
Other comprehensive income before reclassifications
|
—
|
|
|
3.7
|
|
|
3.7
|
|
Amounts reclassified from accumulated other comprehensive income
(2)
|
1.3
|
|
|
(1.7
|
)
|
|
(0.4
|
)
|
Net current-period other comprehensive income
|
1.3
|
|
|
2.0
|
|
|
3.3
|
|
Allocation of accumulated other comprehensive loss to noncontrolling interest
|
0.2
|
|
|
—
|
|
|
0.2
|
|
Balance as of December 31, 2016
|
$
|
(13.2
|
)
|
|
$
|
(10.7
|
)
|
|
$
|
(23.9
|
)
|
(1)
All amounts are net of tax. Amounts in parentheses indicate debits.
(2)
Includes amounts allocated to noncontrolling interest.
Equity Method Investment
During 2008, Millennium Pipeline, in which CPG has an equity investment, entered into
three
interest rate swap agreements with a notional amount totaling
$420.0 million
with
seven
counterparties. During August 2010, Millennium Pipeline completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of
two
tranches of notes totaling
$725.0 million
,
$375.0 million
at
5.33%
due
June 30, 2027
and
$350.0 million
at
6.00%
due
June 30, 2032
. Upon the issuance of these notes, Millennium Pipeline repaid all outstanding borrowings under its credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were primarily accounted for as cash flow hedges by Millennium Pipeline. As an equity method investment, CPG is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss of
$13.2 million
, net of tax, related to these terminated interest rate swaps is being amortized over a
15
year period ending
June 2025
into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of
$13.2 million
and
$14.3 million
at
December 31, 2016
and
December 31, 2015
, respectively, is included in unrealized losses on cash flow hedges above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
AFUDC Equity
|
$
|
34.9
|
|
|
$
|
28.3
|
|
|
$
|
11.0
|
|
Miscellaneous
|
0.2
|
|
|
1.0
|
|
|
(2.2
|
)
|
Total Other, net
|
$
|
35.1
|
|
|
$
|
29.3
|
|
|
$
|
8.8
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Interest on long-term debt
|
$
|
111.0
|
|
|
$
|
67.5
|
|
|
$
|
—
|
|
Interest on short-term borrowings
|
0.2
|
|
|
1.4
|
|
|
—
|
|
Debt discount/cost amortization
(1)
|
10.2
|
|
|
3.1
|
|
|
—
|
|
Allowance for funds used during construction
|
(5.1
|
)
|
|
(6.8
|
)
|
|
—
|
|
Other
|
2.8
|
|
|
2.4
|
|
|
—
|
|
Total Interest Expense
(2)
|
$
|
119.1
|
|
|
$
|
67.6
|
|
|
$
|
—
|
|
(1)
Debt discount/cost amortization for
2016
primarily consists of the accelerated amortization of
$5.7 million
of deferred costs associated with the CPG and CPPL revolving credit facilities. Refer to Note 5, "Short-term Borrowings" for additional information regarding the early termination of the revolving credit facilities.
(2)
Refer to Note 4, "Transactions with Affiliates" for a discussion of interest expense-affiliated for the
year ended
December 31, 2016
,
2015
and
2014
.
Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. As of December 31, 2016, TransCanada's Executive Vice President and President, Natural Gas Pipelines is the chief operating decision maker.
At
December 31, 2016
, CPG's operations comprise
one
operating segment. CPG's segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services and development of mineral rights positions. The chief operating decision maker evaluates the performance of CPG operations and determines how to allocate resources on a consolidated basis.
22.
Supplemental Cash Flow Information
The following tables provide additional information regarding the CPG’s Statements of Consolidated and Combined Cash Flows for the years ended
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
(in millions)
|
2016
|
|
2015
|
|
2014
|
Supplemental Disclosures of Cash Flow Information
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
Capital expenditures included in current liabilities
(1)
|
$
|
146.1
|
|
|
$
|
128.4
|
|
|
$
|
78.5
|
|
Schedule of interest and income taxes paid:
|
|
|
|
|
|
Cash paid for interest, net of interest capitalized amounts
|
$
|
111.1
|
|
|
$
|
96.9
|
|
|
$
|
53.6
|
|
Cash paid for income taxes
(2)
|
4.1
|
|
|
32.3
|
|
|
21.2
|
|
(1)
Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated Balance Sheets.
(2)
Cash paid for income taxes for the year ended December 31, 2015 includes
$20.9 million
paid to NiSource under the Tax Allocation Agreement.
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
23. Concentration of Credit Risk
Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for
greater than 10% of total operating revenues
in the years ended
December 31, 2016
,
2015
and
2014
. The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
2016
|
|
2015
|
|
2014
|
(in millions)
|
Total Operating Revenues
|
|
Percentage of Total Operating Revenues
|
|
Total Operating Revenues
|
|
Percentage of Total Operating Revenues
|
|
Total Operating Revenues
|
|
Percentage of Total Operating Revenues
|
Columbia Gas of Ohio
(1)
|
$
|
169.7
|
|
|
12.3
|
%
|
|
$
|
167.3
|
|
|
12.5
|
%
|
|
$
|
168.5
|
|
|
12.5
|
%
|
(1)
Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release agreements with third parties which ultimately can decrease the net revenue amount CPG receives from Columbia Gas of Ohio in any given period.
The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of CPG.
|
|
24.
|
Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
2016
|
|
|
|
|
|
|
|
Total Operating Revenues
|
$
|
364.5
|
|
|
$
|
313.9
|
|
|
$
|
327.1
|
|
|
$
|
376.5
|
|
Operating Income (Loss)
|
151.7
|
|
|
91.5
|
|
|
(53.0
|
)
|
|
127.4
|
|
Income (Loss) from Continuing Operations
|
86.6
|
|
|
48.6
|
|
|
(49.6
|
)
|
|
68.1
|
|
Results from Discontinued Operations - net of taxes
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net Income (Loss) Attributable to CPG
|
72.2
|
|
|
38.9
|
|
|
(52.5
|
)
|
|
58.2
|
|
2015
|
|
|
|
|
|
|
|
Total Operating Revenues
|
$
|
340.0
|
|
|
$
|
316.1
|
|
|
$
|
320.9
|
|
|
$
|
357.9
|
|
Operating Income
|
162.7
|
|
|
107.3
|
|
|
135.9
|
|
|
122.2
|
|
Income from Continuing Operations
|
97.1
|
|
|
60.1
|
|
|
74.9
|
|
|
75.4
|
|
Results from Discontinued Operations - net of taxes
|
—
|
|
|
(0.3
|
)
|
|
(0.1
|
)
|
|
—
|
|
Net Income Attributable to CPG
|
90.0
|
|
|
50.8
|
|
|
63.0
|
|
|
63.4
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
25. Condensed Consolidating Financial Statements
On
May 22, 2015
, CPG closed its private placement of
$2,750.0 million
in aggregated principal amount of its senior notes (the "Notes"). Please see Note 6, "Long-Term Debt" for further discussion of the Notes. The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by three of CPG's subsidiaries, CEG, Columbia OpCo and OpCo GP. CEG is a 100% owned subsidiary of CPG. In lieu of providing separate financial statements for CEG, the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X have been included.
The following supplemental condensed consolidating financial information reflects CPG’s separate accounts, the combined accounts of CEG and Other Subsidiaries of CEG and CPG, including guarantors Columbia OpCo and OpCo GP, the consolidating adjustments and eliminations and the Issuer’s consolidated accounts for the dates and periods indicated. Separate financial statements have been provided for Columbia OpCo and OpCo GP based on Rule 3-10 of the SEC's Regulation S-X. For purposes of the following consolidating information, CPG’s and CEG's investment in its subsidiaries is accounted for under the equity method of accounting.
CONDENSED CONSOLIDATING BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG Consolidated
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
38.8
|
|
|
$
|
30.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
79.9
|
|
Accounts receivable, net
|
—
|
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
194.1
|
|
|
—
|
|
|
194.2
|
|
Accounts receivable-affiliated
|
799.6
|
|
|
579.5
|
|
|
—
|
|
|
—
|
|
|
190.0
|
|
|
(1,513.3
|
)
|
|
55.8
|
|
Materials and supplies, at average cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.0
|
|
|
—
|
|
|
26.0
|
|
Exchange gas receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27.7
|
|
|
—
|
|
|
27.7
|
|
Deferred property taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61.2
|
|
|
—
|
|
|
61.2
|
|
Taxes receivable
|
68.6
|
|
|
43.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(112.2
|
)
|
|
—
|
|
Prepayments and other
|
0.3
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
28.2
|
|
|
—
|
|
|
28.9
|
|
Total Current Assets
|
907.3
|
|
|
653.6
|
|
|
—
|
|
|
—
|
|
|
538.3
|
|
|
(1,625.5
|
)
|
|
473.7
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
446.7
|
|
|
—
|
|
|
446.7
|
|
Consolidated affiliates
|
5,421.1
|
|
|
7,482.0
|
|
|
6,089.2
|
|
|
—
|
|
|
—
|
|
|
(18,992.3
|
)
|
|
—
|
|
Other investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.8
|
|
|
—
|
|
|
0.8
|
|
Total Investments
|
5,421.1
|
|
|
7,482.0
|
|
|
6,089.2
|
|
|
—
|
|
|
447.5
|
|
|
(18,992.3
|
)
|
|
447.5
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,461.2
|
|
|
—
|
|
|
10,461.2
|
|
Accumulated depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,126.2
|
)
|
|
—
|
|
|
(3,126.2
|
)
|
Net Property, Plant and Equipment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,335.0
|
|
|
—
|
|
|
7,335.0
|
|
Other Noncurrent Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory assets
|
—
|
|
|
56.5
|
|
|
—
|
|
|
—
|
|
|
116.4
|
|
|
—
|
|
|
172.9
|
|
Goodwill
|
—
|
|
|
—
|
|
|
1,975.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,975.5
|
|
Notes receivable-affiliated
|
1,848.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,848.2
|
)
|
|
—
|
|
Postretirement and postemployment benefits assets
|
—
|
|
|
0.8
|
|
|
—
|
|
|
—
|
|
|
121.4
|
|
|
(0.4
|
)
|
|
121.8
|
|
Deferred income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
84.8
|
|
|
(84.8
|
)
|
|
—
|
|
Deferred charges and other
|
1.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9.6
|
|
|
—
|
|
|
11.3
|
|
Total Other Noncurrent Assets
|
1,849.9
|
|
|
57.3
|
|
|
1,975.5
|
|
|
—
|
|
|
332.2
|
|
|
(1,933.4
|
)
|
|
2,281.5
|
|
Total Assets
|
$
|
8,178.3
|
|
|
$
|
8,192.9
|
|
|
$
|
8,064.7
|
|
|
$
|
—
|
|
|
$
|
8,653.0
|
|
|
$
|
(22,551.2
|
)
|
|
$
|
10,537.7
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING BALANCE SHEETS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG Consolidated
|
LIABILITIES, TEMPORARY EQUITY AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term borrowings-affiliated
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
570.8
|
|
|
$
|
—
|
|
|
$
|
923.6
|
|
|
$
|
(1,494.4
|
)
|
|
$
|
—
|
|
Accounts payable
|
—
|
|
|
0.6
|
|
|
—
|
|
|
—
|
|
|
69.8
|
|
|
—
|
|
|
70.4
|
|
Accounts payable-affiliated
|
7.0
|
|
|
5.1
|
|
|
0.8
|
|
|
—
|
|
|
10.0
|
|
|
(18.9
|
)
|
|
4.0
|
|
Customer deposits
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17.3
|
|
|
—
|
|
|
17.3
|
|
Taxes accrued
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
229.1
|
|
|
(112.2
|
)
|
|
116.9
|
|
Interest accrued
|
9.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
9.4
|
|
Exchange gas payable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27.2
|
|
|
—
|
|
|
27.2
|
|
Deferred revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.9
|
|
|
—
|
|
|
3.9
|
|
Accrued capital expenditures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111.4
|
|
|
—
|
|
|
111.4
|
|
Accrued compensation and related costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
62.3
|
|
|
—
|
|
|
62.3
|
|
Other accruals
|
0.1
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
109.5
|
|
|
—
|
|
|
110.1
|
|
Total Current Liabilities
|
16.4
|
|
|
6.2
|
|
|
571.6
|
|
|
—
|
|
|
1,564.2
|
|
|
(1,625.5
|
)
|
|
532.9
|
|
Noncurrent Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
2,728.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,728.6
|
|
Long-term debt-affiliated
|
—
|
|
|
1,217.3
|
|
|
—
|
|
|
—
|
|
|
630.9
|
|
|
(1,848.2
|
)
|
|
—
|
|
Deferred income taxes
|
42.8
|
|
|
1,542.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84.8
|
)
|
|
1,500.4
|
|
Accrued liability for postretirement and postemployment benefits
|
0.7
|
|
|
6.4
|
|
|
—
|
|
|
—
|
|
|
25.5
|
|
|
(0.4
|
)
|
|
32.2
|
|
Regulatory liabilities
|
—
|
|
|
10.2
|
|
|
—
|
|
|
—
|
|
|
263.4
|
|
|
—
|
|
|
273.6
|
|
Asset retirement obligations
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20.8
|
|
|
—
|
|
|
20.8
|
|
Other noncurrent liabilities
|
0.4
|
|
|
1.8
|
|
|
—
|
|
|
—
|
|
|
57.6
|
|
|
—
|
|
|
59.8
|
|
Total Noncurrent Liabilities
|
2,772.5
|
|
|
2,778.1
|
|
|
—
|
|
|
—
|
|
|
998.2
|
|
|
(1,933.4
|
)
|
|
4,615.4
|
|
Total Liabilities
|
2,788.9
|
|
|
2,784.3
|
|
|
571.6
|
|
|
—
|
|
|
2,562.4
|
|
|
(3,558.9
|
)
|
|
5,148.3
|
|
Temporary Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable noncontrolling interest
|
952.9
|
|
|
952.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(952.9
|
)
|
|
952.9
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
Additional paid-in capital
|
4,513.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,513.8
|
|
Accumulated deficit
|
(53.5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
(53.5
|
)
|
Net parent investment
|
—
|
|
|
4,479.3
|
|
|
7,516.2
|
|
|
—
|
|
|
6,117.5
|
|
|
(18,113.0
|
)
|
|
—
|
|
Accumulated other comprehensive loss
|
(23.9
|
)
|
|
(23.6
|
)
|
|
(23.1
|
)
|
|
—
|
|
|
(26.9
|
)
|
|
73.6
|
|
|
(23.9
|
)
|
Total Equity
|
4,436.5
|
|
|
4,455.7
|
|
|
7,493.1
|
|
|
—
|
|
|
6,090.6
|
|
|
(18,039.4
|
)
|
|
4,436.5
|
|
Total Liabilities, Temporary Equity and Equity
|
$
|
8,178.3
|
|
|
$
|
8,192.9
|
|
|
$
|
8,064.7
|
|
|
$
|
—
|
|
|
$
|
8,653.0
|
|
|
$
|
(22,551.2
|
)
|
|
$
|
10,537.7
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING BALANCE SHEETS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2015
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
800.0
|
|
|
$
|
46.7
|
|
|
$
|
1.9
|
|
|
$
|
—
|
|
|
$
|
82.3
|
|
|
$
|
—
|
|
|
$
|
930.9
|
|
Accounts receivable, net
|
—
|
|
|
5.6
|
|
|
—
|
|
|
—
|
|
|
146.8
|
|
|
—
|
|
|
152.4
|
|
Accounts receivable-affiliated
|
14.6
|
|
|
85.6
|
|
|
3.4
|
|
|
—
|
|
|
156.4
|
|
|
(260.0
|
)
|
|
—
|
|
Materials and supplies, at average cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32.8
|
|
|
—
|
|
|
32.8
|
|
Exchange gas receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19.0
|
|
|
—
|
|
|
19.0
|
|
Deferred property taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52.0
|
|
|
—
|
|
|
52.0
|
|
Prepayments and other
|
0.3
|
|
|
10.1
|
|
|
—
|
|
|
—
|
|
|
43.8
|
|
|
(5.7
|
)
|
|
48.5
|
|
Total Current Assets
|
814.9
|
|
|
148.0
|
|
|
5.3
|
|
|
—
|
|
|
533.1
|
|
|
(265.7
|
)
|
|
1,235.6
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
438.1
|
|
|
—
|
|
|
438.1
|
|
Consolidated affiliates
|
5,174.6
|
|
|
7,569.8
|
|
|
5,608.9
|
|
|
—
|
|
|
—
|
|
|
(18,353.3
|
)
|
|
—
|
|
Other investments
|
12.0
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
13.8
|
|
Total Investments
|
5,186.6
|
|
|
7,570.1
|
|
|
5,608.9
|
|
|
—
|
|
|
439.6
|
|
|
(18,353.3
|
)
|
|
451.9
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,052.3
|
|
|
—
|
|
|
9,052.3
|
|
Accumulated depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,988.6
|
)
|
|
—
|
|
|
(2,988.6
|
)
|
Net Property, Plant and Equipment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,063.7
|
|
|
—
|
|
|
6,063.7
|
|
Other Noncurrent Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory assets
|
—
|
|
|
35.1
|
|
|
—
|
|
|
—
|
|
|
142.6
|
|
|
—
|
|
|
177.7
|
|
Goodwill
|
—
|
|
|
—
|
|
|
1,975.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,975.5
|
|
Notes receivable-affiliated
|
1,848.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,848.2
|
)
|
|
—
|
|
Postretirement and postemployment benefits assets
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
115.6
|
|
|
(0.4
|
)
|
|
115.7
|
|
Deferred income taxes
|
18.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18.9
|
)
|
|
—
|
|
Deferred charges and other
|
4.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.6
|
|
|
—
|
|
|
15.5
|
|
Total Other Noncurrent Assets
|
1,872.0
|
|
|
35.6
|
|
|
1,975.5
|
|
|
—
|
|
|
268.8
|
|
|
(1,867.5
|
)
|
|
2,284.4
|
|
Total Assets
|
$
|
7,873.5
|
|
|
$
|
7,753.7
|
|
|
$
|
7,589.7
|
|
|
$
|
—
|
|
|
$
|
7,305.2
|
|
|
$
|
(20,486.5
|
)
|
|
$
|
10,035.6
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING BALANCE SHEETS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2015
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term borrowings
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15.0
|
|
|
$
|
—
|
|
|
$
|
15.0
|
|
Short-term borrowings-affiliated
|
99.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
134.3
|
|
|
(233.3
|
)
|
|
—
|
|
Accounts payable
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56.7
|
|
|
—
|
|
|
56.8
|
|
Accounts payable-affiliated
|
10.8
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
11.1
|
|
|
(26.7
|
)
|
|
—
|
|
Customer deposits
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17.9
|
|
|
—
|
|
|
17.9
|
|
Taxes accrued
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111.7
|
|
|
(5.7
|
)
|
|
106.0
|
|
Interest accrued
|
9.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
9.5
|
|
Exchange gas payable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18.6
|
|
|
—
|
|
|
18.6
|
|
Deferred revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15.0
|
|
|
—
|
|
|
15.0
|
|
Accrued capital expenditures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100.1
|
|
|
—
|
|
|
100.1
|
|
Accrued compensation and related costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51.9
|
|
|
—
|
|
|
51.9
|
|
Other accruals
|
—
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
69.7
|
|
|
—
|
|
|
70.0
|
|
Total Current Liabilities
|
119.3
|
|
|
5.1
|
|
|
—
|
|
|
—
|
|
|
602.1
|
|
|
(265.7
|
)
|
|
460.8
|
|
Noncurrent Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
2,725.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,725.6
|
|
Long-term debt-affiliated
|
—
|
|
|
1,217.3
|
|
|
—
|
|
|
—
|
|
|
630.9
|
|
|
(1,848.2
|
)
|
|
—
|
|
Deferred income taxes
|
—
|
|
|
1,350.4
|
|
|
—
|
|
|
—
|
|
|
16.6
|
|
|
(18.9
|
)
|
|
1,348.1
|
|
Accrued liability for postretirement and postemployment benefits
|
0.3
|
|
|
8.3
|
|
|
—
|
|
|
—
|
|
|
41.2
|
|
|
(0.4
|
)
|
|
49.4
|
|
Regulatory liabilities
|
—
|
|
|
10.5
|
|
|
—
|
|
|
—
|
|
|
311.1
|
|
|
—
|
|
|
321.6
|
|
Asset retirement obligations
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25.7
|
|
|
—
|
|
|
25.7
|
|
Other noncurrent liabilities
|
15.3
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
75.9
|
|
|
—
|
|
|
91.4
|
|
Total Noncurrent Liabilities
|
2,741.2
|
|
|
2,586.7
|
|
|
—
|
|
|
—
|
|
|
1,101.4
|
|
|
(1,867.5
|
)
|
|
4,561.8
|
|
Total Liabilities
|
2,860.5
|
|
|
2,591.8
|
|
|
—
|
|
|
—
|
|
|
1,703.5
|
|
|
(2,133.2
|
)
|
|
5,022.6
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
Additional paid-in capital
|
4,032.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,032.7
|
|
Retained earnings
|
46.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46.9
|
|
Net parent investment
|
—
|
|
|
4,232.3
|
|
|
7,615.4
|
|
|
—
|
|
|
5,631.3
|
|
|
(17,479.0
|
)
|
|
—
|
|
Accumulated other comprehensive loss
|
(27.0
|
)
|
|
(26.8
|
)
|
|
(25.7
|
)
|
|
—
|
|
|
(29.6
|
)
|
|
82.1
|
|
|
(27.0
|
)
|
Total CPG Equity
|
4,056.6
|
|
|
4,205.5
|
|
|
7,589.7
|
|
|
—
|
|
|
5,601.7
|
|
|
(17,396.9
|
)
|
|
4,056.6
|
|
Noncontrolling Interest
|
956.4
|
|
|
956.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(956.4
|
)
|
|
956.4
|
|
Total Equity
|
5,013.0
|
|
|
5,161.9
|
|
|
7,589.7
|
|
|
—
|
|
|
5,601.7
|
|
|
(18,353.3
|
)
|
|
5,013.0
|
|
Total Liabilities and Equity
|
$
|
7,873.5
|
|
|
$
|
7,753.7
|
|
|
$
|
7,589.7
|
|
|
$
|
—
|
|
|
$
|
7,305.2
|
|
|
$
|
(20,486.5
|
)
|
|
$
|
10,035.6
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,155.1
|
|
|
$
|
—
|
|
|
$
|
1,155.1
|
|
Storage revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
196.5
|
|
|
—
|
|
|
196.5
|
|
Other revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.4
|
|
|
—
|
|
|
30.4
|
|
Total Operating Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,382.0
|
|
|
—
|
|
|
1,382.0
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
146.6
|
|
|
0.8
|
|
|
—
|
|
|
—
|
|
|
716.0
|
|
|
(0.2
|
)
|
|
863.2
|
|
Operation and maintenance-affiliated
|
3.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3.7
|
)
|
|
—
|
|
Depreciation and amortization
|
—
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|
172.1
|
|
|
—
|
|
|
172.8
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16.6
|
)
|
|
—
|
|
|
(16.6
|
)
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.1
|
|
|
—
|
|
|
26.1
|
|
Property and other taxes
|
0.1
|
|
|
1.4
|
|
|
0.1
|
|
|
—
|
|
|
81.6
|
|
|
—
|
|
|
83.2
|
|
Total Operating Expenses
|
150.4
|
|
|
2.9
|
|
|
0.1
|
|
|
—
|
|
|
979.2
|
|
|
(3.9
|
)
|
|
1,128.7
|
|
Equity Earnings in Unconsolidated Affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64.3
|
|
|
—
|
|
|
64.3
|
|
Equity Earnings in Consolidated Affiliates
|
284.0
|
|
|
465.2
|
|
|
477.9
|
|
|
—
|
|
|
—
|
|
|
(1,227.1
|
)
|
|
—
|
|
Operating Income
|
133.6
|
|
|
462.3
|
|
|
477.8
|
|
|
—
|
|
|
467.1
|
|
|
(1,223.2
|
)
|
|
317.6
|
|
Other Income (Deductions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
(121.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3.2
|
)
|
|
5.1
|
|
|
(119.1
|
)
|
Interest expense-affiliated
|
(2.1
|
)
|
|
(45.0
|
)
|
|
(3.7
|
)
|
|
—
|
|
|
(31.6
|
)
|
|
80.3
|
|
|
(2.1
|
)
|
Other, net
|
81.1
|
|
|
4.6
|
|
|
—
|
|
|
—
|
|
|
34.8
|
|
|
(85.4
|
)
|
|
35.1
|
|
Total Other Deductions, net
|
(42.0
|
)
|
|
(40.4
|
)
|
|
(3.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(86.1
|
)
|
Income from Continuing Operations before Income Taxes
|
91.6
|
|
|
421.9
|
|
|
474.1
|
|
|
—
|
|
|
467.1
|
|
|
(1,223.2
|
)
|
|
231.5
|
|
Income Taxes
|
(62.1
|
)
|
|
137.8
|
|
|
—
|
|
|
—
|
|
|
2.1
|
|
|
—
|
|
|
77.8
|
|
Income from Continuing Operations
|
153.7
|
|
|
284.1
|
|
|
474.1
|
|
|
—
|
|
|
465.0
|
|
|
(1,223.2
|
)
|
|
153.7
|
|
Income from Discontinued Operations-net of taxes
|
0.2
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
0.2
|
|
Net Income
|
153.9
|
|
|
284.3
|
|
|
474.1
|
|
|
—
|
|
|
465.0
|
|
|
(1,223.4
|
)
|
|
153.9
|
|
Less: Net income attributable to noncontrolling interest
|
37.1
|
|
|
37.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(37.1
|
)
|
|
37.1
|
|
Net Income Attributable to CPG
|
$
|
116.8
|
|
|
$
|
247.2
|
|
|
$
|
474.1
|
|
|
$
|
—
|
|
|
$
|
465.0
|
|
|
$
|
(1,186.3
|
)
|
|
$
|
116.8
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,054.4
|
|
|
$
|
—
|
|
|
$
|
1,054.4
|
|
Transportation revenues-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47.5
|
|
|
—
|
|
|
47.5
|
|
Storage revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
171.4
|
|
|
—
|
|
|
171.4
|
|
Storage revenues-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.2
|
|
|
—
|
|
|
26.2
|
|
Other revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
35.4
|
|
|
—
|
|
|
35.4
|
|
Total Operating Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,334.9
|
|
|
—
|
|
|
1,334.9
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
20.5
|
|
|
(1.2
|
)
|
|
—
|
|
|
—
|
|
|
632.8
|
|
|
—
|
|
|
652.1
|
|
Operation and maintenance-affiliated
|
2.2
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
52.5
|
|
|
(2.2
|
)
|
|
52.9
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
139.9
|
|
|
—
|
|
|
139.9
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55.3
|
)
|
|
—
|
|
|
(55.3
|
)
|
Impairment of long-lived assets
|
—
|
|
|
1.8
|
|
|
—
|
|
|
—
|
|
|
0.6
|
|
|
—
|
|
|
2.4
|
|
Property and other taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75.3
|
|
|
—
|
|
|
75.3
|
|
Total Operating Expenses
|
22.7
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
845.8
|
|
|
(2.2
|
)
|
|
867.3
|
|
Equity Earnings in Unconsolidated Affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.5
|
|
|
—
|
|
|
60.5
|
|
Equity Earnings in Consolidated Affiliates
|
341.2
|
|
|
529.4
|
|
|
529.6
|
|
|
—
|
|
|
—
|
|
|
(1,400.2
|
)
|
|
—
|
|
Operating Income
|
318.5
|
|
|
528.4
|
|
|
529.6
|
|
|
—
|
|
|
549.6
|
|
|
(1,398.0
|
)
|
|
528.1
|
|
Other Income (Deductions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
(73.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.5
|
)
|
|
6.9
|
|
|
(67.6
|
)
|
Interest expense-affiliated
|
(2.5
|
)
|
|
(40.8
|
)
|
|
—
|
|
|
—
|
|
|
(26.8
|
)
|
|
40.8
|
|
|
(29.3
|
)
|
Other, net
|
45.4
|
|
|
0.5
|
|
|
3.5
|
|
|
—
|
|
|
27.6
|
|
|
(47.7
|
)
|
|
29.3
|
|
Total Other Deductions, net
|
(30.1
|
)
|
|
(40.3
|
)
|
|
3.5
|
|
|
—
|
|
|
(0.7
|
)
|
|
—
|
|
|
(67.6
|
)
|
Income from Continuing Operations before Income Taxes
|
288.4
|
|
|
488.1
|
|
|
533.1
|
|
|
—
|
|
|
548.9
|
|
|
(1,398.0
|
)
|
|
460.5
|
|
Income Taxes
|
(19.1
|
)
|
|
146.6
|
|
|
—
|
|
|
—
|
|
|
25.5
|
|
|
—
|
|
|
153.0
|
|
Income from Continuing Operations
|
307.5
|
|
|
341.5
|
|
|
533.1
|
|
|
—
|
|
|
523.4
|
|
|
(1,398.0
|
)
|
|
307.5
|
|
Loss from Discontinued Operations-net of taxes
|
(0.4
|
)
|
|
(0.4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
(0.4
|
)
|
Net Income
|
307.1
|
|
|
341.1
|
|
|
533.1
|
|
|
—
|
|
|
523.4
|
|
|
(1,397.6
|
)
|
|
307.1
|
|
Less: Net income attributable to noncontrolling interest
|
39.9
|
|
|
39.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39.9
|
)
|
|
39.9
|
|
Net Income Attributable to CPG
|
$
|
267.2
|
|
|
$
|
301.2
|
|
|
$
|
533.1
|
|
|
$
|
—
|
|
|
$
|
523.4
|
|
|
$
|
(1,357.7
|
)
|
|
$
|
267.2
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
990.8
|
|
|
$
|
—
|
|
|
$
|
990.8
|
|
Transportation revenues-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
95.7
|
|
|
—
|
|
|
95.7
|
|
Storage revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
144.0
|
|
|
—
|
|
|
144.0
|
|
Storage revenues-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
53.2
|
|
|
—
|
|
|
53.2
|
|
Other revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64.3
|
|
|
—
|
|
|
64.3
|
|
Total Operating Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,348.0
|
|
|
—
|
|
|
1,348.0
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
—
|
|
|
(2.6
|
)
|
|
—
|
|
|
—
|
|
|
631.0
|
|
|
—
|
|
|
628.4
|
|
Operation and maintenance-affiliated
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
122.7
|
|
|
—
|
|
|
123.2
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
118.8
|
|
|
—
|
|
|
118.8
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34.5
|
)
|
|
—
|
|
|
(34.5
|
)
|
Property and other taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67.1
|
|
|
—
|
|
|
67.1
|
|
Total Operating Expenses
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
|
—
|
|
|
905.1
|
|
|
—
|
|
|
903.0
|
|
Equity Earnings in Unconsolidated Affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46.6
|
|
|
—
|
|
|
46.6
|
|
Equity Earnings in Consolidated Affiliates
|
268.7
|
|
|
269.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(538.3
|
)
|
|
—
|
|
Operating Income
|
268.7
|
|
|
271.7
|
|
|
—
|
|
|
—
|
|
|
489.5
|
|
|
(538.3
|
)
|
|
491.6
|
|
Other Income (Deductions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(62.0
|
)
|
|
—
|
|
|
(62.0
|
)
|
Other, net
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
8.9
|
|
|
—
|
|
|
8.8
|
|
Total Other Deductions, net
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
(53.1
|
)
|
|
—
|
|
|
(53.2
|
)
|
Income from Continuing Operations before Income Taxes
|
268.7
|
|
|
271.6
|
|
|
—
|
|
|
—
|
|
|
436.4
|
|
|
(538.3
|
)
|
|
438.4
|
|
Income Taxes
|
—
|
|
|
2.9
|
|
|
—
|
|
|
—
|
|
|
166.8
|
|
|
—
|
|
|
169.7
|
|
Income from Continuing Operations
|
268.7
|
|
|
268.7
|
|
|
—
|
|
|
—
|
|
|
269.6
|
|
|
(538.3
|
)
|
|
268.7
|
|
Loss from Discontinued Operations-net of taxes
|
(0.6
|
)
|
|
(0.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.6
|
|
|
(0.6
|
)
|
Net Income
|
$
|
268.1
|
|
|
$
|
268.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
269.6
|
|
|
$
|
(537.7
|
)
|
|
$
|
268.1
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
(in millions, net of taxes)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG Consolidated
|
Net Income
|
$
|
153.9
|
|
|
$
|
284.3
|
|
|
$
|
474.1
|
|
|
$
|
—
|
|
|
$
|
465.0
|
|
|
$
|
(1,223.4
|
)
|
|
$
|
153.9
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gain (loss) on cash flow hedges
|
1.3
|
|
|
(0.8
|
)
|
|
—
|
|
|
—
|
|
|
2.1
|
|
|
(1.3
|
)
|
|
1.3
|
|
Unrecognized pension and OPEB benefit
|
2.0
|
|
|
1.7
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
(2.0
|
)
|
|
2.0
|
|
Total other comprehensive income
|
3.3
|
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
|
(3.3
|
)
|
|
3.3
|
|
Total Comprehensive Income
|
157.2
|
|
|
285.2
|
|
|
474.1
|
|
|
—
|
|
|
467.4
|
|
|
(1,226.7
|
)
|
|
157.2
|
|
Less: Comprehensive Income-noncontrolling interest
|
37.3
|
|
|
37.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(37.3
|
)
|
|
37.3
|
|
Comprehensive Income-controlling interests
|
$
|
119.9
|
|
|
$
|
247.9
|
|
|
$
|
474.1
|
|
|
$
|
—
|
|
|
$
|
467.4
|
|
|
$
|
(1,189.4
|
)
|
|
$
|
119.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
(in millions, net of taxes)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG Consolidated
|
Net Income
|
$
|
307.1
|
|
|
$
|
341.1
|
|
|
$
|
533.1
|
|
|
$
|
—
|
|
|
$
|
523.4
|
|
|
$
|
(1,397.6
|
)
|
|
$
|
307.1
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gain (loss) on cash flow hedges
|
0.2
|
|
|
(1.6
|
)
|
|
—
|
|
|
—
|
|
|
1.8
|
|
|
(0.2
|
)
|
|
0.2
|
|
Unrecognized pension and OPEB benefit
|
5.2
|
|
|
5.4
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
(5.2
|
)
|
|
5.2
|
|
Total other comprehensive income
|
5.4
|
|
|
3.8
|
|
|
—
|
|
|
—
|
|
|
1.6
|
|
|
(5.4
|
)
|
|
5.4
|
|
Total Comprehensive Income
|
312.5
|
|
|
344.9
|
|
|
533.1
|
|
|
—
|
|
|
525.0
|
|
|
(1,403.0
|
)
|
|
312.5
|
|
Less: Comprehensive Income-noncontrolling interest
|
40.0
|
|
|
40.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40.0
|
)
|
|
40.0
|
|
Comprehensive Income-controlling interests
|
$
|
272.5
|
|
|
$
|
304.9
|
|
|
$
|
533.1
|
|
|
$
|
—
|
|
|
$
|
525.0
|
|
|
$
|
(1,363.0
|
)
|
|
$
|
272.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
(in millions, net of taxes)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG Consolidated
|
Net Income
|
$
|
268.1
|
|
|
$
|
268.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
269.6
|
|
|
$
|
(537.7
|
)
|
|
$
|
268.1
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gain (loss) on cash flow hedges
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
(1.0
|
)
|
|
1.0
|
|
Unrecognized pension and OPEB cost
|
(9.7
|
)
|
|
(9.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9.7
|
|
|
(9.7
|
)
|
Total other comprehensive income
|
(8.7
|
)
|
|
(9.7
|
)
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
8.7
|
|
|
(8.7
|
)
|
Total Comprehensive Income
|
$
|
259.4
|
|
|
$
|
258.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
270.6
|
|
|
$
|
(529.0
|
)
|
|
$
|
259.4
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Net Cash Flows from Operating Activities
|
$
|
(213.6
|
)
|
|
$
|
473.7
|
|
|
$
|
(3.0
|
)
|
|
$
|
—
|
|
|
$
|
712.0
|
|
|
$
|
(608.9
|
)
|
|
$
|
360.2
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,438.1
|
)
|
|
—
|
|
|
(1,438.1
|
)
|
Insurance recoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
—
|
|
|
3.0
|
|
Change in short-term lendings-affiliated
|
(736.1
|
)
|
|
(490.4
|
)
|
|
3.3
|
|
|
—
|
|
|
(37.9
|
)
|
|
1,261.1
|
|
|
—
|
|
Proceeds from disposition of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.4
|
|
|
—
|
|
|
10.4
|
|
Contributions to equity investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6.2
|
)
|
|
—
|
|
|
(6.2
|
)
|
Distributions from equity investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.2
|
|
|
—
|
|
|
2.2
|
|
Other investing activities
|
10.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9.7
|
)
|
|
—
|
|
|
0.6
|
|
Net Cash Flows (used for) provided by Investing Activities
|
(725.8
|
)
|
|
(490.4
|
)
|
|
3.3
|
|
|
—
|
|
|
(1,476.3
|
)
|
|
1,261.1
|
|
|
(1,428.1
|
)
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in short-term borrowings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15.0
|
)
|
|
—
|
|
|
(15.0
|
)
|
Change in short-term borrowings-affiliated
|
401.0
|
|
|
—
|
|
|
570.8
|
|
|
—
|
|
|
789.3
|
|
|
(1,261.1
|
)
|
|
500.0
|
|
Payment of short-term borrowings-affiliated
|
(500.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(500.0
|
)
|
Payment of capital lease obligations and other debt related costs
|
(1.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.3
|
)
|
|
—
|
|
|
(5.4
|
)
|
Issuance of common stock to TransCanada
|
500.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
500.1
|
|
Quarterly distributions to unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(76.9
|
)
|
|
76.9
|
|
|
—
|
|
Distribution to noncontrolling interest in Columbia OpCo
|
—
|
|
|
—
|
|
|
(573.0
|
)
|
|
—
|
|
|
—
|
|
|
573.0
|
|
|
—
|
|
Distribution to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41.0
|
)
|
|
(41.0
|
)
|
Acquisition of treasury stock
|
(6.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6.2
|
)
|
Dividends paid - common stock
|
(105.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(105.1
|
)
|
Dividends paid - TransCanada
|
(110.5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(110.5
|
)
|
Net Cash Flows from (used for) Financing Activities
|
178.2
|
|
|
—
|
|
|
(2.2
|
)
|
|
—
|
|
|
693.1
|
|
|
(652.2
|
)
|
|
216.9
|
|
Change in cash and cash equivalents
|
(761.2
|
)
|
|
(16.7
|
)
|
|
(1.9
|
)
|
|
—
|
|
|
(71.2
|
)
|
|
—
|
|
|
(851.0
|
)
|
Cash and cash equivalents at beginning of period
|
800.0
|
|
|
46.7
|
|
|
1.9
|
|
|
—
|
|
|
82.3
|
|
|
—
|
|
|
930.9
|
|
Cash and Cash Equivalents at End of Period
|
$
|
38.8
|
|
|
$
|
30.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
79.9
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Net Cash Flows from Operating Activities
|
$
|
(29.7
|
)
|
|
$
|
(49.6
|
)
|
|
$
|
3.5
|
|
|
$
|
—
|
|
|
$
|
589.5
|
|
|
$
|
(20.2
|
)
|
|
$
|
493.5
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
(32.7
|
)
|
|
—
|
|
|
—
|
|
|
(1,181.0
|
)
|
|
32.7
|
|
|
(1,181.0
|
)
|
Insurance recoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.1
|
|
|
—
|
|
|
2.1
|
|
Change in short-term lendings-affiliated
|
—
|
|
|
(83.9
|
)
|
|
(3.3
|
)
|
|
—
|
|
|
(0.6
|
)
|
|
233.3
|
|
|
145.5
|
|
Proceeds from disposition of assets
|
—
|
|
|
26.2
|
|
|
—
|
|
|
—
|
|
|
84.1
|
|
|
(32.7
|
)
|
|
77.6
|
|
Contributions to equity investees
|
—
|
|
|
(1,217.3
|
)
|
|
(446.2
|
)
|
|
—
|
|
|
(1.4
|
)
|
|
1,663.5
|
|
|
(1.4
|
)
|
Distributions from equity investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16.0
|
|
|
—
|
|
|
16.0
|
|
Other investing activities
|
(5.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22.2
|
)
|
|
—
|
|
|
(27.4
|
)
|
Net Cash Flows used for Investing Activities
|
(5.2
|
)
|
|
(1,307.7
|
)
|
|
(449.5
|
)
|
|
—
|
|
|
(1,103.0
|
)
|
|
1,896.8
|
|
|
(968.6
|
)
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in short-term borrowings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15.0
|
|
|
—
|
|
|
15.0
|
|
Change in short-term borrowings-affiliated
|
99.0
|
|
|
(5.1
|
)
|
|
—
|
|
|
—
|
|
|
(113.1
|
)
|
|
(233.3
|
)
|
|
(252.5
|
)
|
Issuance of long-term debt
|
2,745.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,745.9
|
|
Debt related costs
|
(27.9
|
)
|
|
6.3
|
|
|
—
|
|
|
—
|
|
|
(2.0
|
)
|
|
—
|
|
|
(23.6
|
)
|
Issuance of long-term debt-affiliated
|
—
|
|
|
1,217.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,217.3
|
|
Payments of long-term debt-affiliated, including current portion
|
(1,848.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(959.6
|
)
|
|
—
|
|
|
(2,807.8
|
)
|
Proceeds from the issuance of common units, net of offering costs
|
—
|
|
|
—
|
|
|
1,170.0
|
|
|
—
|
|
|
(1.6
|
)
|
|
—
|
|
|
1,168.4
|
|
Issuance of common stock, net of offering costs
|
1,394.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,394.7
|
|
Contribution of capital from parent
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,663.5
|
|
|
(1,663.5
|
)
|
|
—
|
|
Distribution of IPO proceeds to NiSource
|
—
|
|
|
—
|
|
|
(500.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(500.0
|
)
|
Distribution to NiSource
|
(1,450.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,450.0
|
)
|
Quarterly distributions to unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43.4
|
)
|
|
43.4
|
|
|
—
|
|
Distribution to noncontrolling interest in Columbia OpCo
|
—
|
|
|
—
|
|
|
(187.3
|
)
|
|
—
|
|
|
—
|
|
|
187.3
|
|
|
—
|
|
Distribution received from Columbia OpCo
|
—
|
|
|
187.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(187.3
|
)
|
|
—
|
|
Distribution to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23.2
|
)
|
|
(23.2
|
)
|
Dividends paid - common stock
|
(79.5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79.5
|
)
|
Transfer from NiSource
|
0.9
|
|
|
(1.8
|
)
|
|
(34.8
|
)
|
|
—
|
|
|
36.5
|
|
|
—
|
|
|
0.8
|
|
Net Cash Flows from Financing Activities
|
834.9
|
|
|
1,404.0
|
|
|
447.9
|
|
|
—
|
|
|
595.3
|
|
|
(1,876.6
|
)
|
|
1,405.5
|
|
Change in cash and cash equivalents
|
800.0
|
|
|
46.7
|
|
|
1.9
|
|
|
—
|
|
|
81.8
|
|
|
—
|
|
|
930.4
|
|
Cash and cash equivalents at beginning of period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
0.5
|
|
Cash and Cash Equivalents at End of Period
|
$
|
800.0
|
|
|
$
|
46.7
|
|
|
$
|
1.9
|
|
|
$
|
—
|
|
|
$
|
82.3
|
|
|
$
|
—
|
|
|
$
|
930.9
|
|
C
olumbia Pipeline Group, Inc.
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
(in millions)
|
CPG
|
|
CEG
|
|
Columbia OpCo
|
|
OpCo GP
|
|
Non-guarantor Subsidiaries
|
|
Consolidating adjustments and eliminations
|
|
CPG
Consolidated
|
Net Cash Flows from Operating Activities
|
$
|
—
|
|
|
$
|
(3.7
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
570.7
|
|
|
$
|
(2.2
|
)
|
|
$
|
564.8
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(747.2
|
)
|
|
—
|
|
|
(747.2
|
)
|
Insurance recoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11.3
|
|
|
—
|
|
|
11.3
|
|
Change in short-term lendings-affiliated
|
—
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
(62.0
|
)
|
|
—
|
|
|
(57.2
|
)
|
Proceeds from disposition of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9.3
|
|
|
—
|
|
|
9.3
|
|
Contributions to equity investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69.2
|
)
|
|
—
|
|
|
(69.2
|
)
|
Other investing activities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7.1
|
)
|
|
—
|
|
|
(7.1
|
)
|
Net Cash Flows used for Investing Activities
|
—
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
(864.9
|
)
|
|
—
|
|
|
(860.1
|
)
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in short-term borrowings-affiliated
|
—
|
|
|
5.2
|
|
|
—
|
|
|
—
|
|
|
(472.3
|
)
|
|
—
|
|
|
(467.1
|
)
|
Debt related costs
|
—
|
|
|
(6.3
|
)
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(6.4
|
)
|
Issuance of long-term debt-affiliated
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
768.9
|
|
|
—
|
|
|
768.9
|
|
Distribution to parent
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.2
|
)
|
|
2.2
|
|
|
—
|
|
Net Cash Flows from Financing Activities
|
—
|
|
|
(1.1
|
)
|
|
—
|
|
|
—
|
|
|
294.3
|
|
|
2.2
|
|
|
295.4
|
|
Change in cash and cash equivalents
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
Cash and cash equivalents at beginning of period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
0.4
|
|
Cash and Cash Equivalents at End of Period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.5
|
|
|
$
|
—
|
|
|
$
|
0.5
|
|
Columbia Pipeline Group, Inc.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
CPG's principal executive officer and its principal financial officer, are responsible for evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). CPG's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including CPG's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, CPG's principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
CPG management, including CPG’s principal executive officer and principal financial officer, are responsible for establishing and maintaining CPG’s internal control over financial reporting, as such term is defined under Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. CPG’s management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2016, CPG conducted an evaluation of its internal control over financial reporting. Based on this evaluation, CPG management concluded that CPG’s internal control over financial reporting was effective as of the end of the period covered by this annual report.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by CPG in the reports that it files or submits under the Exchange Act is accumulated and communicated to CPG’s management, including its principal executive officer and its principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls
There have been no changes in CPG’s internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to affect, CPG’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
Columbia Pipeline Group, Inc.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
We have engaged Deloitte & Touche LLP ("Deloitte") as our independent registered public accounting firm. The following table sets forth fees we have paid to Deloitte & Touche LLP for the years ended December 31, 2016 and 2015.
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
2015
|
Audit Fees
(1)(2)
|
|
$
|
3.4
|
|
$
|
2.9
|
|
Audit-Related Fees
(3)
|
|
0.9
|
|
0.1
|
|
Tax Fees
(4)
|
|
0.1
|
|
—
|
|
All Other Fees
(5)
|
|
—
|
|
—
|
|
Total
|
|
$
|
4.4
|
|
$
|
3.0
|
|
(1)
These are fees for professional services performed by Deloitte for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Form 10-Q filings, and services that are normally provided in connection with statutory and regulatory filings or engagements.
(2)
These are fees for the assurance and related services performed by Deloitte that are reasonably related to the performance of the audit or review of the Company’s financial statements. In 2016, these fees include services provided by Deloitte in connection with the Merger. In 2015, these fees include services provided by Deloitte in connection with Columbia Pipeline Partners LP’s initial public offering of its outstanding limited partnership interests.
(3)
Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits, agreed upon procedures required to comply with financial, accounting or regulatory reporting and assistance with internal control documentation requirements.
(4)
Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.
(5)
All other fees represent fees for services not classifiable under the other categories listed in the table above.
Audit Committee Pre-Approval Policies and Procedures
During fiscal year 2016 until the closing of the Merger on July 1, 2016, the Audit and Risk Committee approved all audit, audit related and non-audit services provided to the Company by Deloitte prior to management engaging the auditor for those purposes. The Audit and Risk Committee’s practice was to consider for pre-approval annually all audit, audit related and non-audit services proposed to be provided by our independent auditors for the fiscal year. Upon the closing of the Merger, the CPG board of directors has taken on the role of the Audit and Risk Committee. Additional fees for other proposed audit-related or non-audit services (not within the scope of the approved audit engagement) may be considered and, if appropriate, approved by the board of directors. In no event, however, will any non-audit related service be approved by the board of directors that would result in the independent auditor no longer being considered independent under the applicable SEC rules. In making its recommendation to appoint Deloitte as our independent auditor, the board of directors has considered whether the provision of the non-audit services rendered by Deloitte is compatible with maintaining that firm’s independence.
Columbia Pipeline Group, Inc.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
The following financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8, "Financial Statements and Supplementary Data."
Exhibits
The exhibits filed herewith as a part of this report on Form 10-K are listed on the Exhibit Index immediately following the signature page. Each management contract or compensatory plan or arrangement of CPG, listed on the Exhibit Index, is separately identified by a (†).
Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of CPG’s subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of CPG and its subsidiaries on a consolidated basis. CPG agrees to furnish a copy of any such instrument to the SEC upon request.
Columbia Pipeline Group, Inc.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
|
|
|
|
|
|
|
|
Columbia Pipeline Group, Inc.
|
|
|
|
(Registrant)
|
|
|
|
|
Date:
|
February 17, 2017
|
By:
|
/s/ STANLEY G. CHAPMAN, III
|
|
|
|
Stanley G. Chapman, III
|
|
|
|
President
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
|
|
|
|
|
|
|
|
|
/s/
|
STANLEY G. CHAPMAN, III
|
|
Director and President
|
Date: February 17, 2017
|
|
|
|
Stanley G. Chapman, III
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
/s/
|
NATHANIEL A. BROWN
|
|
Controller and Principal Financial Officer
|
Date: February 17, 2017
|
|
|
|
Nathaniel A. Brown
|
|
(Principal Financial Officer and
Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
|
/s/
|
RONALD L. COOK
|
|
Director
|
Date: February 17, 2017
|
|
|
|
Ronald L. Cook
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
BRANDON M. ANDERSON
|
|
Director
|
Date: February 17, 2017
|
|
|
|
Brandon M. Anderson
|
|
|
|
|
|
|
|
|
|
|
Columbia Pipeline Group, Inc.
EXHIBIT INDEX
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with (†) are management contracts or compensatory plan or agreement of Columbia Pipeline Group, Inc.
|
|
|
(2.1)
|
Separation and Distribution Agreement, dated as of June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 2.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
|
|
|
(2.2)
|
Agreement and Plan of Merger, dated as of March 17, 2016, by and among TransCanada PipeLines Limited, TransCanada PipeLine USA Ltd., Taurus Merger Sub Inc., Columbia Pipeline Group, Inc., and solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII thereof, TransCanada Corporation (Incorporated by reference to Exhibit 2.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on March 18, 2016).
|
|
|
(2.3)
|
Agreement and Plan of Merger dated as of November 1, 2016, by and among Columbia Pipeline Group, Inc., Columbia Pipeline Partners L.P., MLP GP and Pony Merger Sub LLC (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K, File No. 001-36838, filed on November 2, 2016).
|
|
|
(3.1)
|
Second Restated Certificate of Incorporation of Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 3.1 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on August 2, 2016).
|
|
|
(3.2)
|
Bylaws of Targus Merger Sub Inc. (Incorporated by reference to Exhibit 3.2 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on August 2, 2016).
|
|
|
(4.1)
|
Indenture, dated as of May 22, 2015, by and among Columbia Pipeline Group, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(4.2)
|
Registration Rights Agreement, dated as of May 22, 2015, by and among Columbia Pipeline Group, Inc., the Guarantors named therein and the Initial Purchasers (Incorporated by reference to Exhibit 4.2 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(4.3)
|
Form of 2.45% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(4.4)
|
Form of 3.30% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(4.5)
|
Form of 4.50% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(4.6)
|
Form of 5.80% Senior Note due 2018 (Incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.1)
|
Revolving Credit Agreement, dated as of December 5, 2014, by and among Columbia Pipeline Group, Inc., as Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent, Barclays Bank PLC, The Bank of Nova Scotia and BNP Paribas, as Co-Documentation Agents and Barclays Bank PLC, Citigroup Global Markets, Inc., The Bank of Nova Scotia, BNP Paribas and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 10.6 to the Columbia Pipeline Group, Inc. Form 10 (File No. 001-36838) filed on February 6, 2015).
|
|
|
(10.2)
|
Revolving Credit Agreement, dated as of December 5, 2014, by and among Columbia Pipeline Partners LP, as Borrower, NiSource Inc., Columbia Pipeline Group, Inc., Columbia Energy Group, CPG OpCo LP, CPG OpCo GP LLC, as Guarantors, the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and The Bank of Tokyo-Mitsubishi UFJ, LTD, as Syndication Agent (Incorporated by reference to Exhibit 10.7 to the Columbia Pipeline Group, Inc. Form 10 (File No. 001-36838) filed on February 6, 2015).
|
|
|
(10.3)
|
Trademark License Agreement, dated as of February 11, 2015, between NiSource Corporate Services Company and Columbia Pipeline Group Services Company filed April 17, 2015. (Incorporated by reference to Exhibit 10.3 to the Columbia Pipeline Group, Inc. Amendment No. 2 Form 10 (File No. 001-36838) filed on April 17, 2015).
|
|
|
Columbia Pipeline Group, Inc.
|
|
|
(10.4)†
|
Employment Offer Letter Agreement, dated May 14, 2008, between NiSource Inc. and Stephen P. Smith, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.21 to the Columbia Pipeline Group, Inc. Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.5)†
|
Retention Bonus Letter Agreement, dated March 11, 2014, between NiSource Inc. and Shawn Patterson, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.22 to the Columbia Pipeline Group, Inc. Form 10 Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.6)†
|
Retention Bonus Letter Agreement, dated September 2, 2014, between NiSource Inc. and Stanley Chapman, assumed by Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.23 to the Columbia Pipeline Group, Inc. Amendment No. 4 to the Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.7)
|
Tax Allocation Agreement, dated June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
|
|
|
(10.8)
|
Employee Matters Agreement, dated June 30, 2015, between NiSource Inc. and Columbia Pipeline Group, Inc., (Incorporated by reference to Exhibit 10.2 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on July 2, 2015).
|
|
|
(10.9)
|
Form of Transition Services Agreement (NiSource to CPG) between NiSource Corporate Services Company and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.4 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.10)
|
Form of Transition Services Agreement (CPG to NiSource) between NiSource Corporate Services Company and Columbia Pipeline Group Services Company (Incorporated by reference to Exhibit 10.5 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.11)†
|
Form of Columbia Pipeline Group, Inc. 2015 Omnibus Plan (Incorporated by reference to Exhibit 10.8 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.12)†
|
Form of Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.9 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.13)†
|
Form of Performance Share Award Agreement (Incorporated by reference to Exhibit 10.10 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.14)†
|
Form of Restricted Stock Unit Award Agreement with Nonemployee Directors (Incorporated by reference to Exhibit 10.11 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.15)†
|
Form of Restricted Stock Unit Award Agreement with Nonemployee Directors of Columbia Pipeline Group, Inc. Relating to Vested by Unpaid NiSource Restricted Stock Units (Incorporated by reference to Exhibit 10.12 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.16)†
|
Form of Director Restricted Stock Unit Award Agreement Relating to Unvested NiSource Restricted Stock Units (Incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.17)†
|
Form of Columbia Pipeline Group, Inc. Phantom Stock Unit Agreement (Incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.18)†
|
Form of Change in Control and Termination Agreement with Robert Skaggs (Incorporated in reference to Exhibit 10.15 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.19)†
|
Form of Change in Control and Termination Agreement with Other Named Executive Officers (Incorporated in reference to Exhibit 10.16 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
Columbia Pipeline Group, Inc.
|
|
|
(10.20)†
|
Form of Columbia Pipeline Group, Inc. Executive Severance Policy (Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.21)†
|
Form of Columbia Pipeline Group Executive Deferred Compensation Plan (Incorporated by reference to Exhibit 10.18 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.22)†
|
Form of Columbia Pipeline Group Savings Restoration Plan (Incorporated by reference to Exhibit 10.19 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.23)†
|
Form of Columbia Pipeline Group Pension Restoration Plan (Incorporated by reference to Exhibit 10.20 to Amendment No. 4 to the Columbia Pipeline Group, Inc. Registration Statement on Form 10 (File No. 001-36838) filed on May 22, 2015).
|
|
|
(10.24)
|
Form of Commercial Paper Dealer Agreement (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on October 6, 2015)
|
|
|
(10.25)
|
Amended and Restated System Money Pool Agreement, dated as of July 1, 2015, by and among Columbia Pipeline Group, Inc., Columbia Pipeline Group Services Company, as administrative agent, and the direct and indirect subsidiaries of Columbia Pipeline Group, Inc. (Incorporated by reference to Exhibit 10.2 to the Columbia Pipeline Group, Inc. Quarterly Report on Form 10-Q (File No. 001-36838) filed on November 3, 2015).
|
|
|
(10.26)
|
Credit Agreement, dated as of December 16, 2016, by and among Columbia Pipeline Group, Inc., as borrower, TransCanada PipeLines Limited, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.1 to the Columbia Pipeline Group, Inc. Current Report on Form 8-K (File No. 001-36838) filed on January 30, 2017).
|
|
|
(12.1)*
|
Ratio of Earnings to Fixed Charges
|
|
|
(23.1)*
|
Consent of Deloitte & Touche LLP
|
|
|
(31.1)*
|
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
(31.2)*
|
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
(32.1)**
|
Certification of Chief Executive Officer, pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
(32.2)**
|
Certification of Chief Financial Officer, pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
(101.INS)*
|
XBRL Instance Document
|
|
|
(101.SCH)*
|
XBRL Schema Document
|
|
|
(101.CAL)*
|
XBRL Calculation Linkbase Document
|
|
|
(101.LAB)*
|
XBRL Labels Linkbase Document
|
|
|
(101.PRE)*
|
XBRL Presentation Linkbase Document
|
|
|
(101.DEF)*
|
XBRL Definition Linkbase Document
|
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