Columbia Pipeline Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - Columbia Pipeline Partners LP	cppl-2016930xex321.htm
EX-32.2 - EXHIBIT 32.2 - Columbia Pipeline Partners LP	cppl-2016930xex322.htm
EX-31.2 - EXHIBIT 31.2 - Columbia Pipeline Partners LP	cppl-2016930xex312.htm
EX-31.1 - EXHIBIT 31.1 - Columbia Pipeline Partners LP	cppl-2016930xex311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-36835

Columbia Pipeline Partners LP

(Exact name of registrant as specified in its charter)



Delaware		51-0658510
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5151 San Felipe St., Suite 2500 Houston, Texas		77056
(Address of principal executive offices)		(Zip Code)

(713) 386-3701

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)

Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer ¨

Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No þ

At October 31, 2016, there were 53,843,466 Common Units and 46,811,398 Subordinated Units outstanding.

COLUMBIA PIPELINE PARTNERS LP

FORM 10-Q QUARTERLY REPORT

FOR THE QUARTER ENDED SEPTEMBER 30, 2016

Table of Contents



			Page

	Defined Terms		3

PART I	FINANCIAL INFORMATION

	Item 1.	Financial Statements - unaudited

		Condensed Consolidated Balance Sheets (unaudited)	5

		Condensed Statements of Consolidated and Combined Operations (unaudited)	7

		Condensed Statements of Consolidated and Combined Comprehensive Income (unaudited)	8

		Condensed Statements of Consolidated and Combined Cash Flows (unaudited)	9

		Condensed Statements of Consolidated Partners' Capital (unaudited)	10

		Notes to Condensed Consolidated and Combined Financial Statements (unaudited)	11

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45

	Item 4.	Controls and Procedures	45

PART II	OTHER INFORMATION

	Item 1.	Legal Proceedings	46

	Item 1A.	Risk Factors	46

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

	Item 3.	Defaults Upon Senior Securities	47

	Item 4.	Mine Safety Disclosures	47

	Item 5.	Other Information	47

	Item 6.	Exhibits	48

	Signature		49

Table of Contents

Columbia Pipeline Partners LP

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

Affiliates and Subsidiaries of Columbia Pipeline Partners LP
CEG	Columbia Energy Group
CEVCO	Columbia Energy Ventures, LLC
CNS Microwave	CNS Microwave, LLC
Columbia Gas Transmission	Columbia Gas Transmission, LLC
Columbia Gulf	Columbia Gulf Transmission, LLC
Columbia Midstream	Columbia Midstream Group, LLC
Columbia OpCo	CPG OpCo LP
CPG	Columbia Pipeline Group, Inc.
CPGSC	Columbia Pipeline Group Services Company
Hardy Storage	Hardy Storage Company, LLC
Millennium Pipeline	Millennium Pipeline Company, L.L.C.
MLP GP	CPP GP LLC
OpCo GP	CPG OpCo GP LLC
Pennant	Pennant Midstream, LLC
TCPL	TransCanada PipeLines Limited
TransCanada	TransCanada Corporation
US Parent	TransCanada PipeLine USA Ltd.

Abbreviations
AFUDC	Allowance for funds used during construction, is the method prescribed by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital and borrowed funds until a project is placed into operation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CAA	Clean Air Act
CCRM	Capital Cost Recovery Mechanism, which is an approved demand charge under the Columbia Gas Transmission modernization settlement
Dth/d	Dekatherms per day
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
IPO	Initial public offering of Columbia Pipeline Partners LP, which was completed on February 11, 2015
IT	Information Technology
LDC	Local distribution companies are involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR	London Interbank Offered Rate
LNG	Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times
MMDth	One million Dekatherms
MMDth/d	One million Dekatherms per day

Table of Contents

Columbia Pipeline Partners LP

DEFINED TERMS (continued)

NAAQS	National Ambient Air Quality Standards
NGA	Natural Gas Act of 1938
NiSource	NiSource Inc.
NiSource Corporate Services	NiSource Corporate Services Company
NiSource Finance	NiSource Finance Corp.
OCI	Other Comprehensive Income (Loss)
OPEB	Other postretirement benefits
ppb	Parts per billion
SEC	Securities and Exchange Commission
throughput	The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period
VIE	Variable Interest Entity

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Columbia Pipeline Partners LP Condensed Consolidated Balance Sheets (unaudited)

(in millions)	September 30, 2016			December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	8.4		$	78.9
Accounts receivable (less reserve of $0.3 and $0.3, respectively)	157.3			145.9
Accounts receivable-affiliated	161.2			149.4
Materials and supplies, at average cost	26.4			32.8
Exchange gas receivable	13.9			18.8
Deferred property taxes	17.7			52.0
Prepayments and other	36.9			33.8
Total Current Assets	421.8			511.6
Investments
Unconsolidated affiliates	440.2			437.1
Other investments	1.8			1.8
Total Investments	442.0			438.9
Property, Plant and Equipment
Property, plant and equipment	10,071.0			8,930.9
Accumulated depreciation and amortization	(3,053.7		)	(2,960.1		)
Net Property, Plant and Equipment	7,017.3			5,970.8
Other Noncurrent Assets
Regulatory assets	135.8			134.1
Goodwill	1,975.5			1,975.5
Postretirement and postemployment benefits assets	117.3			120.5
Deferred charges and other	9.9			10.6
Total Other Noncurrent Assets	2,238.5			2,240.7
Total Assets	$	10,119.6		$	9,162.0

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP Condensed Consolidated Balance Sheets (unaudited) (continued)

(in millions, except unit amounts)	September 30, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	—		$	15.0
Short-term borrowings-affiliated	1,121.5			42.1
Accounts payable	74.6			49.9
Accounts payable-affiliated	31.4			86.3
Customer deposits	16.5			17.8
Taxes accrued	73.9			108.2
Exchange gas payable	13.7			18.2
Deferred revenue	5.6			15.0
Accrued capital expenditures	171.0			95.9
Accrued compensation and related costs	33.7			26.6
Other accruals	73.5			43.8
Total Current Liabilities	1,615.4			518.8
Noncurrent Liabilities
Long-term debt-affiliated	630.9			630.9
Deferred income taxes	1.0			1.0
Accrued liability for postretirement and postemployment benefits	35.2			36.1
Regulatory liabilities	272.9			309.7
Asset retirement obligations	22.5			25.3
Other noncurrent liabilities	62.7			63.5
Total Noncurrent Liabilities	1,025.2			1,066.5
Total Liabilities	2,640.6			1,585.3
Commitments and Contingencies (Refer to Note 15)
Equity and Partners' Capital
Common unitholders-public (53,843,466 and 53,834,784 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)	955.3			958.5
Subordinated unitholders-CEG (46,811,398 units issued and outstanding)	298.6			304.0
Accumulated other comprehensive loss	(3.7		)	(4.0		)
Total Columbia Pipeline Partners LP partners' equity and capital	1,250.2			1,258.5
Noncontrolling Interest in Columbia OpCo	6,228.8			6,318.2
Total Equity and Partners' Capital	7,479.0			7,576.7
Total Liabilities and Equity and Partners' Capital	$	10,119.6		$	9,162.0

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Condensed Statements of Consolidated and Combined Operations (unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per unit amounts)	2016			2015			2016			2015
Operating Revenues
Transportation revenues	$	269.8		$	265.8		$	836.4		$	751.0
Transportation revenues-affiliated	—			—			—			47.1
Storage revenues	48.9			49.5			147.7			122.3
Storage revenues-affiliated	—			—			—			26.2
Other revenues	7.8			4.7			19.1			28.2
Total Operating Revenues	326.5			320.0			1,003.2			974.8
Operating Expenses
Operation and maintenance	152.2			144.9			357.5			392.9
Operation and maintenance-affiliated	116.2			37.4			198.1			112.1
Depreciation and amortization	38.8			33.4			114.1			98.7
Gain on sale of assets	(9.8		)	(39.0		)	(15.8		)	(52.6		)
Impairment of long-lived assets	11.9			0.6			11.9			0.6
Property and other taxes	17.9			15.2			58.9			53.3
Total Operating Expenses	327.2			192.5			724.7			605.0
Equity Earnings in Unconsolidated Affiliates	16.0			15.3			48.1			44.2
Operating Income	15.3			142.8			326.6			414.0
Other Income (Deductions)
Interest expense	(0.3		)	(1.2		)	(2.8		)	(1.2		)
Interest expense-affiliated	(8.4		)	(6.4		)	(22.6		)	(24.1		)
Other, net	14.3			9.4			30.3			18.6
Total Other Income (Deductions), net	5.6			1.8			4.9			(6.7		)
Income before Income Taxes	20.9			144.6			331.5			407.3
Income Taxes	—			—			0.1			23.7
Net Income	20.9			144.6			331.4			383.6
Less: Predecessor net income prior to IPO on February 11, 2015	—			—			—			42.7
Net income subsequent to IPO	20.9			144.6			331.4			340.9
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO	18.0			122.6			283.1			289.3
Net income attributable to limited partners subsequent to IPO	$	2.9		$	22.0		$	48.3		$	51.6
Net income attributable to partners' ownership interest subsequent to IPO per limited partner unit (basic and diluted)
Common units	$	0.05		$	0.22		$	0.48		$	0.52
Subordinated units	—			0.22			0.43			0.51
Weighted average limited partner units outstanding (basic and diluted)
Common units	53.8			53.8			53.8			53.8
Subordinated units	46.8			46.8			46.8			46.8

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Condensed Statements of Consolidated and Combined Comprehensive Income (unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions, net of taxes for periods prior to IPO)	2016		2015			2016		2015
Net Income	$	20.9	$	144.6		$	331.4	$	383.6
Other comprehensive income
Net unrealized gain on cash flow hedges⁽¹⁾	0.6		0.4			1.6		1.0
Unrecognized pension and OPEB benefit (cost)⁽²⁾⁽³⁾	0.1		(0.2		)	0.1		(0.2		)
Total other comprehensive income	0.7		0.2			1.7		0.8
Total comprehensive income	21.6		144.8			333.1		384.4
Total other comprehensive income prior to IPO	—		—			—		0.1
Predecessor net income prior to IPO	—		—			—		42.7
Total comprehensive income prior to IPO	—		—			—		42.8
Total comprehensive income subsequent to IPO	21.6		144.8			333.1		341.6
Less: Comprehensive income attributable to noncontrolling interest subsequent to IPO	18.6		122.8			284.5		289.9
Comprehensive income attributable to limited partners subsequent to IPO	$	3.0	$	22.0		$	48.6	$	51.7

⁽¹⁾Net unrealized gains on derivatives qualifying as cash flow hedges, net of zero tax expense for the three months ended September 30, 2016 and 2015, and zero and $0.1 million tax expense for the nine months ended September 30, 2016 and 2015, respectively.

⁽²⁾Unrecognized pension and OPEB benefit (cost), net of zero tax expense for the three months ended September 30, 2016 and 2015, and zero tax expense for the nine months ended September 30, 2016 and 2015.

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

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP Condensed Statements of Consolidated and Combined Cash Flows (unaudited)

Nine Months Ended September 30, (in millions)	2016			2015
Operating Activities
Net Income	$	331.4		$	383.6
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization	114.1			98.7
Deferred income taxes and investment tax credits	—			10.5
Deferred revenue	(2.7		)	0.4
Equity-based compensation expense and profit sharing contribution	1.2			4.5
Gain on sale of assets	(15.8		)	(52.6		)
Impairment of long-lived assets	11.9			0.6
Equity earnings in unconsolidated affiliates	(48.1		)	(44.2		)
Amortization of debt related costs	1.6			0.3
AFUDC equity	(29.7		)	(15.0		)
Distributions of earnings received from equity investees	51.0			44.1
Changes in Assets and Liabilities:
Accounts receivable	(3.5		)	3.2
Accounts receivable-affiliated	7.2			27.9
Accounts payable	16.7			18.1
Accounts payable-affiliated	(55.0		)	(20.3		)
Customer deposits	(1.2		)	(23.8		)
Taxes accrued	(34.8		)	(25.6		)
Exchange gas receivable/payable	0.4			0.4
Other accruals	10.6			(1.7		)
Prepayments and other current assets	37.7			20.1
Regulatory assets/liabilities	(10.9		)	43.7
Postretirement and postemployment benefits	(0.7		)	(26.9		)
Deferred charges and other noncurrent assets	2.4			(3.5		)
Other noncurrent liabilities	7.6			(3.6		)
Net Cash Flows from Operating Activities	391.4			438.9
Investing Activities
Capital expenditures	(1,073.0		)	(775.9		)
Insurance recoveries	—			2.1
Change in short-term lendings-affiliated	(19.1		)	(265.3		)
Proceeds from disposition of assets	9.9			55.0
Contributions to equity investees	(6.2		)	(1.4		)
Distributions from equity investees	1.6			15.1
Other investing activities	(6.7		)	(19.1		)
Net Cash Flows used for Investing Activities	(1,093.5		)	(989.5		)
Financing Activities
Change in short-term borrowings	(15.0		)	20.0
Change in short-term borrowings-affiliated	1,079.3			(245.0		)
Payments of long-term debt-affiliated, including current portion	—			(957.8		)
Payments of capital lease obligations and other debt related costs	(1.9		)	—
Proceeds from the issuance of common units, net of offering costs	—			1,168.4
Distribution of IPO proceeds to parent	—			(500.0		)
Contribution of capital from parent	—			1,217.3
Quarterly distributions to unitholders	(56.9		)	(26.0		)
Distribution to noncontrolling interest in Columbia OpCo	(373.9		)	(69.9		)
Net Cash Flows from Financing Activities	631.6			607.0
Change in cash and cash equivalents	(70.5		)	56.4
Cash and cash equivalents at beginning of period	78.9			0.5
Cash and Cash Equivalents at End of Period	$	8.4		$	56.9

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Condensed Statements of Consolidated and Combined Equity and Partners' Capital (unaudited)



(in millions)	Common Unitholders			Subordinated Unitholders			Noncontrolling Interest			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2016	$	958.5		$	304.0		$	6,318.2		$	(4.0	)	$	7,576.7
Net income	27.2			21.1			283.1			—			331.4
Other comprehensive income	—			—			1.4			0.3			1.7
Quarterly distributions to unitholders	(30.4		)	(26.5		)	—			—			(56.9		)
Distributions to the noncontrolling interest in Columbia OpCo	—			—			(373.9		)	—			(373.9		)
Balance as of September 30, 2016	$	955.3		$	298.6		$	6,228.8		$	(3.7	)	$	7,479.0



	Predecessor			Partnership
(in millions)	Net Parent Investment			Common Unitholders			Subordinated Unitholders			Noncontrolling Interest			Accumulated Other Comprehensive Loss			Total
Balance as of January 1, 2015	$	4,188.0		$	—		$	—		$	—		$	(16.7	)	$	4,171.3
Net income from January 1, 2015 through February 10, 2015	42.7			—			—			—			—			42.7
Other comprehensive income, net of tax, from January 1, 2015 through February 10, 2015	—			—			—			—			0.1			0.1
Contribution of capital from parent	1,217.3			—			—			—			—			1,217.3
Predecessor net tax liabilities not assumed by Columbia OpCo⁽¹⁾	1,232.5			—			—			—			(10.3		)	1,222.2
Contributed/Noncontributed Net Parent Investment Adjustments⁽²⁾	(7.7		)	—			—			—			—			(7.7		)
Balance as of February 11, 2015 (prior to IPO)	6,672.8			—			—			—			(26.9		)	6,645.9
Allocation of net investment to unitholders	(6,672.8		)	—			487.1			6,185.7			—			—
Allocation of accumulated other comprehensive loss to noncontrolling interest	—			—			—			(22.7		)	22.7			—
Net proceeds from IPO	—			1,168.4			—			—			—			1,168.4
Purchase of additional interest in Columbia OpCo⁽³⁾	—			(227.1		)	(197.3		)	424.4			—			—
Distribution to the noncontrolling interest in Columbia OpCo	—			—			—			(569.9		)	—			(569.9		)
Net income from February 11, 2015 through September 30, 2015	—			27.9			23.7			289.3			—			340.9
Other comprehensive income, from February 11, 2015 through September 30, 2015	—			—			—			0.6			0.1			0.7
Quarterly distribution for the period from February 11, 2015 to September 30, 2015 to unitholders	—			(13.9		)	(12.1		)	—			—			(26.0		)
Transfers from parent	—			0.2			—			1.1			—			1.3
Balance as of September 30, 2015	$	—		$	955.5		$	301.4		$	6,308.5		$	(4.1	)	$	7,561.3

⁽¹⁾Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-IPO, as well as associated regulatory assets and liabilities.

⁽²⁾Reflects the removal of amounts related to Crossroads Pipeline Company, CPGSC, Central Kentucky Transmission Company and 1% of the 50% interest in Hardy Storage that were included in the Predecessor but were not contributed to the Partnership, as well as the inclusion of CNS Microwave, which was not part of the Predecessor.

⁽³⁾Represents the purchase of an additional 8.4% limited partner interest in Columbia OpCo, recorded at the historical carrying value of Columbia OpCo's net assets after giving effect to the $1,168.4 million equity contribution. This decreases common unitholders and subordinated unitholders equity by the same amount it increases noncontrolling interest because the Partnership's purchase price for its additional 8.4% interest in Columbia OpCo exceeded book value.

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited)

1. Basis of Accounting Presentation

Columbia Pipeline Partners LP (the "Partnership") was formed in Delaware on December 5, 2007. CEG owns the general partner of the Partnership and all of the Partnership's subordinated units and incentive distribution rights. On February 11, 2015, NiSource contributed its subsidiary CEG to CPG. Following this contribution, CPG owns and operates, through its subsidiaries, approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation's largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of CPG. Prior to July 1, 2015, CPG was a wholly owned subsidiary of NiSource. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource (the "Separation"). As a result of the Separation, CPG became an independent publicly traded company. Columbia Pipeline Partners LP Predecessor (the "Predecessor") is comprised of NiSource's Columbia Pipeline Group Operations reportable segment.

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. With the completion of the transaction, TransCanada owns the general partner of the Partnership, all of the Partnership's incentive distribution rights and all of the Partnership's subordinated units, which represent a 46.5% limited partnership interest in the Partnership. The Partnership is now effectively managed by TransCanada. The Partnership incurred approximately $110.4 million of Merger related costs within operation and maintenance and property and other taxes, including approximately $101.3 million of employee related costs. Additionally, as a result of the Merger, the Partnership recognized an impairment charge of $11.9 million related to the cancellation of IT system upgrades that were in process prior to the Merger.

The Partnership is engaged in regulated interstate gas transportation and storage services for LDCs, marketers, producers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses 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 tariffs at rates subject to FERC approval.

Concurrent with the completed IPO, refer to Note 2 for a discussion of IPO results, NiSource contributed substantially all of the assets and operations of the Predecessor to Columbia OpCo, a Delaware limited partnership formed by CEG, which, prior to the Separation, was a wholly owned subsidiary of NiSource, and OpCo GP, a wholly owned subsidiary of the Partnership. The contribution is considered to be a reorganization of entities under common control. Subsequent to the IPO, the Partnership owns a 15.7% limited partner interest in Columbia OpCo and CEG owns the remaining 84.3% limited partner interest. MLP GP, a wholly owned subsidiary of CEG, serves as the general partner of the Partnership. OpCo GP serves as the general partner of Columbia OpCo. CPGSC provides services to the Partnership pursuant to an omnibus agreement. MLP GP, the Partnership, Columbia OpCo and OpCo GP have all adopted a fiscal year end of December 31. Through ownership of Columbia OpCo's general partner, the Partnership controls all of Columbia OpCo's assets and operations. Under ASC 810, Columbia OpCo is determined to be a VIE. As the Partnership has a significant economic interest in Columbia OpCo and has the power to direct the activities of Columbia OpCo through that interest and its 100% ownership interest in OpCo GP, the Partnership is determined to be the primary beneficiary of Columbia OpCo and consolidates Columbia OpCo and CEG's retained interest of 84.3% is recorded as noncontrolling interest in the Partnership's consolidated financial statements.

For periods subsequent to the closing of the IPO, the financial statements included in this quarterly report are the financial statements and accounting records of the Partnership. For periods prior to the closing of the IPO, the financial statements included in this quarterly report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows:


•	The Condensed Consolidated Balance Sheets (unaudited) consist of the consolidated balance sheets of the Partnership as of September 30, 2016 and December 31, 2015.


•	The Condensed Statements of Consolidated and Combined Operations (unaudited) consist of consolidated results of the Partnership for the three months ended September 30, 2016 and 2015.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)


•	The Condensed Statements of Consolidated and Combined Operations (unaudited) consist of consolidated results of the Partnership for the nine months ended September 30, 2016 and for the period from February 11, 2015 through September 30, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015.


•	The Condensed Statements of Consolidated and Combined Comprehensive Income (unaudited) consist of consolidated results of the Partnership for the three months ended September 30, 2016 and 2015.


•	The Condensed Statements of Consolidated and Combined Comprehensive Income (unaudited) consist of consolidated results of the Partnership for the nine months ended September 30, 2016 and for the period from February 11, 2015 through September 30, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015.


•	The Condensed Statements of Consolidated and Combined Cash Flows (unaudited) consist of consolidated cash flows of the Partnership for the nine months ended September 30, 2016 and for the period from February 11, 2015 through September 30, 2015 and the combined cash flows of the Predecessor for the period from January 1, 2015 through February 10, 2015.


•	The Condensed Statements of Consolidated and Combined Equity and Partners' Capital (unaudited) consist of consolidated activity of the Partnership for the nine months ended September 30, 2016 and for the period from February 11, 2015 through September 30, 2015 and the combined activity of the Predecessor for the period from January 1, 2015 through February 10, 2015.

The Condensed Consolidated and Combined Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although the Partnership believes that the disclosures made are adequate to make the information not misleading. These financial statements should be read in conjunction with the consolidated and combined financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2015 (the "2015 Form 10-K"). These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the Partnership's results of operations and financial position in accordance with GAAP in the United States of America. Amounts reported in the Condensed Statements of Consolidated and Combined Operations (unaudited) are not necessarily indicative of amounts expected for the respective annual periods. All intercompany transactions and balances have been eliminated.

2. Initial Public Offering

On February 6, 2015, the Partnership's common units began trading on the New York Stock Exchange under the ticker symbol "CPPL." On February 11, 2015, the Partnership completed its offering of 53,833,107 common units at a price to the public of $23.00 per unit, including 7,021,709 common units that were issued pursuant to the exercise in full of the underwriters' over-allotment option. The Partnership received net proceeds of $1,168.4 million from the offering. At or prior to the closing of the IPO the following transactions occurred:


•	CEG contributed $1,217.3 million of capital to certain subsidiaries of the Predecessor to repay intercompany debt owed to NiSource Finance. CEG entered into new intercompany debt agreements with NiSource Finance for $1,217.3 million;


•	CEG contributed substantially all of the subsidiaries in the Predecessor to Columbia OpCo;


•	CEG assumed responsibility for all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-IPO, as well as associated regulatory assets and liabilities;


•	CEG contributed a 7.3% limited partner interest in Columbia OpCo to the Partnership in exchange for 46,811,398 subordinated units in the Partnership and all of the Partnership's incentive distribution rights;


•	The Partnership purchased from Columbia OpCo an additional 8.4% limited partner interest in exchange for $1,168.4 million from the net proceeds of the IPO, net of underwriting discounts, structuring fees and offering expenses of approximately $69.8 million, resulting in the Partnership owning a 15.7% limited partner interest in Columbia OpCo.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Net income attributable to the Partnership	$	2.9	$	22.0	$	48.3	$	51.6
Decrease in partnership equity for the purchase of an additional 8.4 percent interest in Columbia OpCo	—		—		—		(424.4		)
Change from net income attributable to the Partnership and transfers to noncontrolling interest	$	2.9	$	22.0	$	48.3	$	(372.8	)


•	Columbia OpCo distributed $500.0 million to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo.

The Partnership entered into an omnibus agreement with CEG and its affiliates (together with a services agreement with CPGSC) at the closing of the IPO that addresses (1) centralized corporate, general and administrative services to be provided by CEG for the Partnership and the reimbursement by the Partnership for the Partnership's portion of these services, (2) the Partnership's right of first offer for CEG's 84.3% interest in Columbia OpCo, (3) the indemnification of the Partnership for certain potential environmental and toxic tort claims losses and expenses associated with the operation of the assets and occurring before the closing date of the IPO and (4) Columbia OpCo's requirement to guarantee future indebtedness that CPG incurs.

3. Recent Accounting Pronouncements

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. The Partnership 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. The Partnership is currently evaluating the impact the adoption of ASU 2016-15 will have on the Condensed Consolidated and Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2017, including interim periods, and the new standard is to be applied retrospectively, with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. In March 2016, the FASB issued ASU 2016-08, which amends the principal-versus-agent implementation guidance and illustrations in ASU 2014-09. Among other things, ASU 2016-08 clarifies that an entity should evaluate whether it is the principal or the agent for each specified good or service promised in a contract with a customer. 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. The Partnership is currently evaluating the impact the adoption of ASU 2014-09, and the related ASUs, will have on the Condensed Consolidated and Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

on the Condensed Consolidated and Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. In August 2015, the FASB issued ASU 2015-15 to clarify the SEC staff's position on these costs in relation to line-of-credit agreements stating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of such arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. The Partnership retrospectively adopted ASU 2015-03 and ASU 2015-15 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Condensed Consolidated or Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The Partnership retrospectively adopted ASU 2015-06 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Condensed Consolidated and Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. The Partnership retrospectively adopted ASU 2015-02 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Condensed Consolidated and Combined Financial Statements (unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (unaudited).

4. Net Income Per Limited Partner Unit

Net income per unit applicable to common units and to subordinated units is computed by dividing the respective limited partners' interest in net income by the weighted-average number of common units and subordinated units outstanding for the period. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units and incentive distribution rights. Basic and diluted net income per unit are the same because the Partnership does not have any potentially dilutive units outstanding for the periods presented.

Pursuant to our cash distribution policy, within 60 days after the end of each quarter, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.1675 per unit, or $0.67 on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

On November 1, 2016, the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period July 1, 2016, through September 30, 2016, of $0.1975 per unit. This distribution is payable on November 18, 2016, to unitholders of record as of November 11, 2016.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

The calculation of net income per unit is as follows:



Three Months Ended September 30, 2016 (in millions, except per unit data)	Limited Partners' Common Units			Limited Partners' Subordinated Units			Incentive Distribution Rights			Total
Net income attributable to partners
Distribution	$	10.6		$	9.3		$	0.1		$	20
Distribution in excess of net income	(7.7		)	(9.3		)	(0.1		)	(17.1		)
Net income attributable to partners	$	2.9		$	—		$	—		$	2.9

Weighted average limited partner units outstanding
Basic and diluted	53.8			46.8						100.6
Net income attributable to partners' ownership interest per limited partner unit
Basic and diluted	$	0.05		$	—					$	0.03

Nine Months Ended September 30, 2016 (in millions, except per unit data)	Limited Partners' Common Units			Limited Partners' Subordinated Units			Incentive Distribution Rights			Total
Net income attributable to partners
Distribution	$	31.3		$	27.4		$	0.1		$	58.8
Distribution in excess of net income	(5.4		)	(7.3		)	2.2			(10.5		)
Net income attributable to partners	$	25.9		$	20.1		$	2.3		$	48.3

Weighted average limited partner units outstanding
Basic and diluted	53.8			46.8						100.6
Net income attributable to partners' ownership interest per limited partner unit
Basic and diluted	$	0.48		$	0.43					$	0.46

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)



Three Months Ended September 30, 2015 (in millions, except per unit data)	Limited Partners' Common Units		Limited Partners' Subordinated Units		Incentive Distribution Rights		Total
Net income attributable to partners
Distribution	$	9.3	$	8.1	$	—	$	17.4
Net income in excess of distribution	2.5		2.1		—		4.6
Net income attributable to partners	$	11.8	$	10.2	$	—	$	22.0

Weighted average limited partner units outstanding
Basic and diluted	53.8		46.8				100.6
Net income attributable to partners' ownership interest per limited partner unit
Basic and diluted	$	0.22	$	0.22			$	0.22

Nine Months Ended September 30, 2015 (in millions, except per unit data)	Limited Partners' Common Units		Limited Partners' Subordinated Units		Incentive Distribution Rights		Total
Net income attributable to partners
Distribution	$	23.2	$	20.3	$	—	$	43.5
Net income in excess of distribution⁽¹⁾	4.7		3.4		—		8.1
Net income attributable to partners	$	27.9	$	23.7	$	—	$	51.6

Weighted average limited partner units outstanding
Basic and diluted	53.8		46.8				100.6
Net income attributable to partners' ownership interest subsequent to IPO per limited partner unit
Basic and diluted	$	0.52	$	0.51			$	0.51

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

5. Transactions with Affiliates

Prior to CPG's separation from NiSource, the Partnership engaged in transactions with subsidiaries of NiSource, which were deemed to be affiliates of the Partnership. The Partnership continues to engage in transactions with subsidiaries of CPG subsequent to the Separation. These affiliate transactions are summarized in the tables below:

Statement of Operations



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Transportation revenues	$	—	$	—	$	—	$	47.1
Storage revenues	—		—		—		26.2
Other revenues	—		—		—		0.2
Operation and maintenance expense	116.2		37.4		198.1		112.1
Interest expense	8.4		6.4		22.6		24.1
Interest income	0.4		0.9		0.7		4.2

Balance Sheet



(in millions)	September 30, 2016		December 31, 2015
Accounts receivable	$	161.2	$	149.4
Short-term borrowings	1,121.5		42.1
Accounts payable	31.4		86.3
Long-term debt	630.9		630.9

Transportation, Storage and Other Revenues. Prior to the Separation, the Partnership provided natural gas transportation, storage and other services to subsidiaries of NiSource, the Partnership's former affiliates. Prior to the IPO, the Predecessor provided similar services to subsidiaries of NiSource.

Operation and Maintenance Expense. The Partnership receives executive, financial, legal, information technology and other administrative and general services from CPGSC. Prior to the IPO, the Predecessor received similar services from NiSource Corporate Services. Expenses incurred as a result of these services consist primarily of employee compensation and benefits, outside services and other expenses. The expenses are charged directly or allocated using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable. However, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity. Subsequent to the completion of the Merger, the Partnership incurred merger related operation and maintenance expense of $78.3 million primarily related to employee and administrative expenses.

Interest Expense and Income. The Partnership was charged interest for long-term debt of $7.6 million and $7.7 million for the three months ended September 30, 2016 and 2015, respectively, offset by associated AFUDC of $1.8 million and $1.7 million for the three months ended September 30, 2016 and 2015, respectively. The Partnership was charged interest for long-term debt of $22.8 million and $27.4 million for the nine months ended September 30, 2016 and 2015, respectively, offset by associated AFUDC of $3.7 million and $4.1 million for the nine months ended September 30, 2016 and 2015, respectively.

Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the date of the IPO. Following the Separation, the agreement is now with CPG. The money pool is available for Columbia OpCo and its subsidiaries' general purposes, including capital expenditures and working capital. This intercompany money pool agreement is discussed in connection with Short-term Borrowings below. Prior to the IPO, the subsidiaries of the Predecessor participated in a similar money pool agreement with NiSource Finance. CPGSC administers the current money pool agreement. The cash accounts maintained by the subsidiaries of Columbia OpCo were, prior to the Separation, swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

NiSource and the subsidiary. Subsequent to the Separation, cash accounts maintained by the subsidiaries of Columbia OpCo are swept into a CPG corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between CPG and the subsidiary. The amount of interest expense and income for short-term borrowings is determined by the net position of each subsidiary in the money pool. The money pool weighted-average interest rate at September 30, 2016 and 2015 was 1.68% and 1.21%, respectively. For the three months ended September 30, 2016 and 2015, the interest expense for short-term borrowings charged was $2.6 million and $0.5 million, respectively. For the nine months ended September 30, 2016 and 2015, the interest expense for short-term borrowings charged was $3.5 million and $0.9 million, respectively.

Accounts Receivable. The Partnership includes in accounts receivable amounts due from the money pool discussed above of $159.5 million and $140.5 million at September 30, 2016 and December 31, 2015, respectively, for subsidiaries of Columbia OpCo in a net deposit position. Also, included in the balance at September 30, 2016 and December 31, 2015 are amounts due from subsidiaries of CPG for transportation and storage services of $1.7 million and $8.9 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Condensed Statements of Consolidated and Combined Cash Flows (unaudited). All other affiliated receivables are included as Operating Activities.

Short-term Borrowings. In connection with the closing of the IPO, the subsidiaries of Columbia OpCo entered into an intercompany money pool agreement with NiSource Finance with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement was with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. Effective July 1, 2016, in connection with the Merger, the $1,500.0 million CPG revolving credit facility was terminated and replaced by a $2,000.0 million revolving credit facility with US Parent.

Included in the balance of Short-term Borrowings at September 30, 2016 and December 31, 2015 is $1,116.5 million and $42.1 million, respectively, which includes those subsidiaries of Columbia OpCo in a net borrower position of the money pool discussed above. On June 24, 2016, the Partnership entered into a $50.0 million intercompany credit agreement with CEG, with a maturity date of December 31, 2016. Loans under the agreement bear interest at the LIBOR, plus 1.075%. As of September 30, 2016, the Partnership had $5.0 million in outstanding borrowings under the agreement, with a weighted average interest rate of 1.79%. Net cash flows related to Short-term Borrowings are included as Financing Activities on the Condensed Statements of Consolidated and Combined Cash Flows (unaudited).

Accounts Payable. The affiliated accounts payable balance primarily includes amounts due for services received from CPGSC and interest payable to CPG.

Long-term Debt. In May 2015, the Partnership's outstanding intercompany debt transferred from NiSource Finance to CPG. The Partnership's long-term financing requirements are satisfied through borrowings from CPG. On January 31, 2016, the Partnership amended its intercompany credit agreement with CPG to extend the maturity date of the note originating on December 9, 2013 from December 31, 2016 to December 31, 2020. The Partnership may borrow at any time from the origination date to December 31, 2016 not to exceed $2.6 billion. From January 1, 2017 to December 31, 2020, the Partnership may borrow at any time not to exceed $2.3 billion. As of the January 2016 amendment, the note carries a fixed interest rate of 4.70% for the outstanding borrowings as of September 30, 2016.

Details of the long-term debt balance are summarized in the table below:



Origination Date	Interest Rate		Maturity Date	September 30, 2016		December 31, 2015
(in millions)
December 9, 2013	4.70	%	December 31, 2020	$	630.9	$	630.9

Dividends. During the nine months ended September 30, 2016, Columbia OpCo distributed $373.0 million to CEG. During the nine months ended September 30, 2015, Columbia OpCo distributed $569.9 million to CEG of which $500.0 million was a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. There were no restrictions on the payment by the Partnership of distributions to CEG.

6. Short-Term Borrowings

As of December 31, 2015, the Partnership 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, the

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

Partnership accelerated the amortization of $1.4 million of deferred costs associated with the revolving credit facility, which are included in interest expense for the nine months ended September 30, 2016.

Given their maturity and turnover is three months or less, cash flows related to the borrowings and repayments of the revolving credit facility are presented net in the Condensed Statements of Consolidated and Combined Cash Flows (unaudited).

7. Gain on Sale of Assets

The Partnership recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. For the three months ended September 30, 2016 and 2015, gains on conveyances amounted to $9.7 million and $36.0 million, respectively, and are included in "Gain on sale of assets" on the Condensed Statements of Consolidated and Combined Operations (unaudited). For the nine months ended September 30, 2016 and 2015, gains on conveyances amounted to $15.7 million and $49.6 million, respectively, and are included in "Gain on sale of assets" on the Condensed Statements of Consolidated and Combined Operations (unaudited). Included in the gains on conveyances is a cash bonus payment of $9.0 million and $35.8 million received by CEVCO from CNX Gas Company LLC during the three and nine months ended September 30, 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 September 30, 2016 and December 31, 2015, deferred gains of approximately $1.3 million and $8.1 million, respectively, were deferred pending performance of future obligations and recorded within "Deferred revenue," on the Condensed Consolidated Balance Sheets (unaudited).

8. Goodwill

The Partnership tests its goodwill for impairment annually as of May 1 unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, referred to as the Columbia Gas Transmission Operations reporting unit, which is consistent with the level of discrete financial information reviewed by management. The Columbia Gas Transmission Operations reporting unit includes the following entities: Columbia Gas Transmission (including its equity method investment in the Millennium Pipeline joint venture), Columbia Gulf and the equity method investment in Hardy Storage. All of the Partnership's goodwill relates to NiSource's acquisition of CEG in 2000, which was contributed to the Partnership prior to the IPO. The Partnership’s goodwill assets at September 30, 2016 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.

GAAP allows entities testing goodwill for impairment the option of performing a qualitative ("step 0") assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that, based on that assessment, it is more likely than not that its fair value is less than its carrying amount.

The Partnership applied the qualitative step 0 analysis to its reporting unit for the annual impairment test performed as of May 1, 2016. For the current year test, the Partnership assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The 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 its reporting unit fair value is less than the reporting unit carrying value.

The Partnership considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. On November 1, 2016, the Partnership announced that it entered into an agreement and plan of merger with CPG, in which CPG will acquire all outstanding common units of the Partnership. The acquisition price leads to a similar valuation of the Partnership as that provided for in the Merger Agreement, providing further evidence that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value. In consideration of all relevant factors, there were no indicators that would require a subsequent goodwill impairment test during the third quarter of 2016.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

9. Asset Retirement Obligations

Changes in the Partnership's liability for asset retirement obligations for the nine months ended September 30, 2016 and 2015 are presented in the table below:



(in millions)	2016			2015
Balance as of January 1,	$	25.3		$	23.2
Noncontributed net parent investment adjustments⁽¹⁾	—			(0.4		)
Accretion expense	0.8			0.9
Additions	—			0.4
Settlements	—			—
Change in estimated cash flows	(3.6		)	(1.6		)
Balance as of September 30,	$	22.5		$	22.5

⁽¹⁾ Reflects the removal of amounts related to Crossroads Pipeline Company, which was included in the Predecessor but was not contributed to the Partnership.

The asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl ("PCB") remediation and asbestos removal at several compressor and measuring stations. The Partnership recognizes that certain assets, which include gas pipelines and natural gas storage wells, will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified.

10. Regulatory Matters

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

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

Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf 's existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf filed a cost and revenue study with the FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. 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. A significant portion of the transmission and storage regulated companies' revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

proceedings with the FERC under Section 4 of the NGA. However, certain operating costs of the Columbia OpCo regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas. The FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies' rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Gas Transmission's long-term plan to modernize its interstate transmission system as discussed above.

11. Equity Method Investments

Certain investments of the Partnership are accounted for under the equity method of accounting. These investments are recorded within "Unconsolidated affiliates" on the Condensed Consolidated Balance Sheets (unaudited) and the Partnership's portion of the results is reflected in "Equity Earnings in Unconsolidated Affiliates" on the Condensed Statements of Consolidated and Combined Operations (unaudited). These investments are integral to the Partnership's business. Contributions are made to these equity investees to fund the Partnership's share of capital projects.

The following table contains contribution and distribution data representing the Partnership's portion based on the Partnership's ownership percentage of each investment:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Millennium Pipeline
Contributions to Millennium Pipeline	$	4.3	$	1.4	$	6.2	$	1.4
Distributions of earnings from Millennium Pipeline	17.5		13.3		41.3		37.5
Hardy Storage
Contributions to Hardy Storage	—		—		—		—
Distributions of earnings from Hardy Storage	—		—		1.4		1.0
Pennant
Contributions to Pennant	—		—		—		—
Distributions of earnings from Pennant	2.3		2.9		8.3		5.6
Return of capital from Pennant	0.8		0.2		1.6		2.4

During the third quarter of 2015, an additional member joined the Pennant joint venture. The member's initial ownership investment in Pennant is 5.00%, and by funding specified, disproportionate investment amounts for future growth projects, the member can invest directly in the growth of Pennant. Such funding will potentially increase the member's 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 50.00% to 47.50%.

12. Income Taxes

The Partnership is a limited partnership and is treated as a partnership for U.S. federal income tax purposes and, therefore, is not liable for entity-level federal income taxes. Amounts presented for 2015 in the combined financial statements relate to income taxes that have been determined on a separate tax return basis for the period prior to the IPO.

The effective tax rates for the nine months ended September 30, 2016 and 2015 were zero and 5.8%, respectively. The effective tax rate for 2015 differs from the Federal tax rate of 35% primarily due to post-IPO income that is not subject to income tax at the partnership level.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

13. Pension and Other Postretirement Benefits

CPG provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of subsidiaries of Columbia OpCo. Prior to the Separation, employees of subsidiaries of Columbia OpCo were covered by defined contribution plans and noncontributory defined benefit retirement plans provided by NiSource. Benefits under the defined benefit retirement plans reflect the employees' compensation, years of service and age at retirement. Additionally, CPG provides health care and life insurance benefits for certain retired employees of subsidiaries of Columbia OpCo. The majority of employees may become eligible for these benefits if they reach retirement age while working for subsidiaries of Columbia OpCo. The expected cost of such benefits is accrued during the employees' years of service. Current rates charged to customers of subsidiaries of Columbia OpCo include postretirement benefit costs. Cash contributions are remitted to trusts, including a grantor trust used to fund benefits of the CPG non-qualified defined benefit plan.

Subsidiaries of Columbia OpCo are participants in the consolidated CPG defined benefit retirement plans (the "Plans") and, therefore, subsidiaries of Columbia OpCo are allocated a ratable portion of CPG's trusts for the Plans in which its employees and retirees participate. As a result, the Partnership follows multiple employer accounting under the provisions of GAAP.

For the nine months ended September 30, 2016, CPG has made no contributions to its pension plans and contributed $1.0 million to its other postretirement benefit plans.

The following table provides the components of the subsidiaries of Columbia OpCo's allocation of net periodic benefits cost for the three and nine months ended September 30, 2016 and 2015:



	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30, (in millions)	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	1.6		$	1.4		$	0.3		$	0.2
Interest cost	3.2			3.3			1.0			1.0
Expected return on assets	(5.2		)	(5.8		)	(3.4		)	(4.4		)
Amortization of prior service (credit) cost	(0.2		)	(0.3		)	(0.1		)	—
Recognized actuarial loss	2.7			2.1			0.1			(0.1		)
Net Periodic Benefit Cost (Income)	2.1			0.7			(2.1		)	(3.3		)
Additional loss recognized due to:
Settlement loss	2.6			—			—			—
Total Net Periodic Benefit Cost (Income)	$	4.7		$	0.7		$	(2.1	)	$	(3.3	)

	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30, (in millions)	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	4.8		$	4.0		$	0.8		$	0.8
Interest cost	11.0			9.4			3.3			3.0
Expected return on assets	(18.5		)	(18.0		)	(11.5		)	(13.0		)
Amortization of prior service (credit) cost	(0.8		)	(0.7		)	(0.4		)	—
Recognized actuarial loss	8.9			6.2			0.2			(0.1		)
Net Periodic Benefit Cost (Income)	5.4			0.9			(7.6		)	(9.3		)
Additional loss recognized due to:
Settlement loss	2.6			—			—			—
Total Net Periodic Benefit Cost (Income)	$	8.0		$	0.9		$	(7.6	)	$	(9.3	)

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

As of July 1, 2016, the CPG pension and other postretirement benefit plans were remeasured as a result of the acquisition by TransCanada. The remeasurement resulted in an increase to the pension benefit obligation, net of plan assets, of $0.4 million, a net decrease to regulatory assets of $0.9 million, and an increase to accumulated other comprehensive loss of $0.1 million. Net periodic pension cost for the remainder of 2016 increased by $0.7 million as a result of the remeasurement. A settlement charge of $2.6 million was recorded as a result of the non-qualified pension plan being terminated in connection with the Merger.

The other postretirement benefits obligation, net of plan assets, decreased by $10.1 million as a result of the remeasurement. Additionally, the remeasurement resulted in an increase to regulatory assets of $8.6 million and a decrease to regulatory liabilities of $1.7 million. The remeasurement resulted in no change to accumulated other comprehensive loss. Net periodic other postretirement benefit cost for the remainder of 2016 increased by $1.0 million as a result of the remeasurement.

The following table provides the key assumptions that were used to calculate the pension and other postretirement benefit obligation and the net periodic benefit cost at the measurement dates of July 1, 2016 and December 31, 2015.



	Pension Benefits				Other Postretirement Benefits
	July 1, 2016		December 31, 2015		July 1, 2016		December 31, 2015
Actuarial Assumptions
Discount Rate	3.75	%	4.05	%	3.95	%	4.28	%
Expected return on assets	6.75	%	8.20	%	6.36	%	8.06	%
Health Care Trend Rates
Trend for 2016					8.80	%	8.38	%
Ultimate Trend					4.50	%	4.50	%
Year Ultimate Trend Reached					2023		2022

14. Fair Value

The Partnership has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits, short-term borrowings and short-term borrowings-affiliated. The Partnership's long-term debt-affiliated is recorded at historical amounts.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Long-term debt-affiliated. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. On January 31, 2016, the Partnership amended its intercompany credit agreement to extend the maturity date and apply a fixed interest rate. Prior to this amendment, the fair value approximated the carrying value as these securities bore interest at variable rates. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the nine months ended September 30, 2016 and for the year ended December 31, 2015, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

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



(in millions)	Carrying Amount as of September 30, 2016		Estimated Fair Value as of September 30, 2016		Carrying Amount as of Dec. 31, 2015		Estimated Fair Value as of Dec. 31, 2015
Long-term debt-affiliated	$	630.9	$	683.2	$	630.9	$	630.9

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

15. Other Commitments and Contingencies

A. Guarantees and Indemnities. In the normal course of its business, the Partnership and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of the parent or certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to the parent or a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the parent or the subsidiaries' intended commercial purposes. The total guarantees and indemnities in existence at September 30, 2016 and the years in which they expire were:



(in millions)	Total		2016		2017		2018		2019		2020		After
Guarantees of debt	$	2,750.0	$	—	$	—	$	500.0	$	—	$	750.0	$	1,500.0

Guarantees of Debt. OpCo GP and Columbia OpCo (together with CEG, the "Guarantors") have guaranteed payment of $2,750.0 million in aggregated principal amount of CPG's senior notes. Each Guarantor is required to comply with covenants under the debt indenture and in the event of default the Guarantors would be obligated to pay the debt's principal and related interest. The Partnership does not anticipate that OpCo GP or Columbia OpCo will have any difficulty maintaining compliance. The guarantees of any Guarantor may be released under certain circumstances.

Lines and Letters of Credit. The Partnership 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. The Partnership maintains a $50.0 million credit facility with CEG, effective June 24, 2016. As of September 30, 2016, the Partnership had $5.0 million in outstanding borrowings. CPG maintained a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit was available. OpCo GP and Columbia OpCo, together with CEG, each fully guaranteed the CPG 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.

CPG's commercial paper program (the "Program") had a Program limit of up to $1,000.0 million. OpCo GP and Columbia OpCo, together with CEG, 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.

B. Other Legal Proceedings. In the normal course of its business, the Partnership has been named as a defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material impact on the Partnership's consolidated and combined financial statements. Please see Item 1 of Part II, Legal Proceedings, for more information.

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

It is the Partnership's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred.

The Partnership records accruals to cover environmental remediation at various sites. The current portion of this accrual is included in “Other accruals” in the Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in “Other noncurrent liabilities” in the Condensed Consolidated Balance Sheets (unaudited).

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

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

the utilization of specific emission control technologies to limit emissions. The actions listed below could require further reductions in emissions from various emission sources. The Partnership will continue to closely monitor developments in these matters.

National Ambient Air Quality Standards. The federal CAA requires the EPA to set NAAQS for particulate matter and five other pollutants considered harmful to public health and the environment. Periodically, the EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by gas transmission operations.

The following NAAQS were recently added or modified:

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

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

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

New Source Performance Standards: On May 12, 2016, the EPA finalized the rule to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The final rule was subsequently published in the Federal Register on June 3, 2016. The Partnership is working with industry groups to litigate and clarify ambiguities within the rule. The Partnership does not have any existing sites that will be impacted by this rule. However, the EPA has announced that it intends to propose additional regulations related to the emission of methane from existing sources in the oil and natural gas sector.

Pipeline Safety

On March 17, 2016, the federal Pipeline and Hazardous Materials Safety Administration ("PHMSA") announced a proposed rulemaking that would, if adopted, impose more stringent requirements for certain gas lines and gathering lines under varying circumstances. Among other things, the proposed rulemaking would extend certain of PHMSA's current regulatory safety programs for gas pipelines beyond "high consequence areas" to cover gas pipelines found in newly defined "moderate consequence areas" that contain as few as 5 dwellings within the potential impact area; require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures ("MAOP"); and require gathering lines in Class I areas, both onshore and offshore, to comply with standards regarding damage prevention, corrosion control (for metallic pipe), public education, MAOP limits, line markers and emergency planning if such gathering lines' nominal design is 8 inches or more. In order to provide clarity and greater certainty on what may constitute a "gathering line," PHMSA is proposing a new definition of that term under the rulemaking, which term would now encompass "a pipeline, or a connected series of pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of the following endpoints" including the "inlet of 1^st gas processing plant;" the "outlet of" a gas treatment facility (not associated with a processing plant or compressor station); the "[o]utlet of the furthermost downstream compressor" leading to a pipeline, or the "point where separate production fields are commingled." Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

guidance from PHMSA in the selection of assessment methods to inspect pipelines. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.

On June 22, 2016, President Obama signed new pipeline safety legislation, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016" (the “PIPES Act”). Extending PHMSA’s statutory mandate through 2019, the PIPES Act establishes or continues the development of stringent requirements affecting pipeline safety including: (i) providing PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing; (ii) having pipeline operators that experience a spill from a liquids pipeline provide safety data sheets for the spilled liquid to the on-scene coordinator predesignated by the EPA and state and local officials within six hours of a telephonic notice; (iii) obligating PHMSA to develop safety standards for natural gas storage facilities by June 22, 2018; (iv) obligating PHMSA to provide feedback to pipeline operators after an inspection, including a briefing within thirty days and a written report with written preliminary findings within ninety days to the extent practicable; (v) requiring annual internal inspection of certain underwater hazardous liquid pipeline facilities in high consequence areas located at depths greater than 150 feet under the surface of the water; and (vi) requiring PHMSA to complete certain of the outstanding mandates under existing legislation and to report to Congress on the status of overdue rulemakings. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.

On October 3, 2016, PHMSA announced a temporary rule authorizing the agency to issue Emergency Orders to address what it deems imminent safety hazards for both liquid and gas pipes. The 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. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

16. Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2016 and 2015:



Three Months Ended September 30, 2016 (in millions)	Gains and Losses on Cash Flow Hedges⁽¹⁾			Pension and OPEB Items⁽¹⁾			Accumulated Other Comprehensive Loss⁽¹⁾
Balance as of July 1, 2016	$	(3.7	)	$	(0.1	)	$	(3.8	)
Other comprehensive income before reclassifications	—			0.2			0.2
Amounts reclassified from accumulated other comprehensive income⁽²⁾	0.6			(0.1		)	0.5
Net current-period other comprehensive income	0.6			0.1			0.7
Allocation of accumulated other comprehensive loss to noncontrolling interest	0.5			0.1			0.6
Balance as of September 30, 2016	$	(3.6	)	$	(0.1	)	$	(3.7	)
⁽¹⁾Amounts in parentheses indicate debits. ⁽²⁾Includes amounts allocated to noncontrolling interest.
Nine Months Ended September 30, 2016 (in millions)	Gains and Losses on Cash Flow Hedges⁽¹⁾			Pension and OPEB Items⁽¹⁾			Accumulated Other Comprehensive Loss⁽¹⁾
Balance as of January 1, 2016	$	(3.9	)	$	(0.1	)	$	(4.0	)
Other comprehensive income before reclassifications	—			0.2			0.2
Amounts reclassified from accumulated other comprehensive income⁽²⁾	1.6			(0.1		)	1.5
Net current-period other comprehensive income	1.6			0.1			1.7
Allocation of accumulated other comprehensive loss to noncontrolling interest	1.3			0.1			1.4
Balance as of September 30, 2016	$	(3.6	)	$	(0.1	)	$	(3.7	)

⁽¹⁾Amounts in parentheses indicate debits.

⁽²⁾Includes amounts allocated to noncontrolling interest.



Three Months Ended September 30, 2015 (in millions)	Gains and Losses on Cash Flow Hedges⁽¹⁾			Pension and OPEB Items⁽¹⁾			Accumulated Other Comprehensive Loss⁽¹⁾
Balance as of July 1, 2015	$	(4.0	)	$	(0.1	)	$	(4.1	)
Other comprehensive income before reclassifications	—			(0.5		)	(0.5		)
Amounts reclassified from accumulated other comprehensive income⁽²⁾	0.4			0.3			0.7
Net current-period other comprehensive income	0.4			(0.2		)	0.2
Allocation of accumulated other comprehensive loss to noncontrolling interest	0.4			(0.2		)	0.2
Balance as of September 30, 2015	$	(4.0	)	$	(0.1	)	$	(4.1	)
⁽¹⁾Amounts in parentheses indicate debits. ⁽²⁾Includes amounts allocated to noncontrolling interest.
Nine Months Ended September 30, 2015 (in millions)	Gains and Losses on Cash Flow Hedges⁽¹⁾⁽³⁾			Pension and OPEB Items⁽¹⁾⁽³⁾			Accumulated Other Comprehensive Loss⁽¹⁾⁽³⁾
Balance as of January 1, 2015	$	(16.6	)	$	(0.1	)	$	(16.7	)
Predecessor net tax liabilities not assumed by Columbia OpCo⁽⁴⁾	(10.2		)	(0.1		)	(10.3		)
Other comprehensive income before reclassifications	—			(0.5		)	(0.5		)
Amounts reclassified from accumulated other comprehensive income⁽²⁾	1.0			0.3			1.3
Net current-period other comprehensive income	1.0			(0.2		)	0.8
Allocation of accumulated other comprehensive loss to noncontrolling interest	(21.8		)	(0.3		)	(22.1		)
Balance as of September 30, 2015	$	(4.0	)	$	(0.1	)	$	(4.1	)

⁽¹⁾Amounts in parentheses indicate debits.

⁽²⁾Includes amounts allocated to noncontrolling interest.

⁽³⁾All amounts prior to the IPO are net of tax.

⁽⁴⁾Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that will continue to be borne by the Partnership post-IPO.

Table of Contents

ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

Equity Investment

Millennium Pipeline is an equity method investment and, therefore, Columbia OpCo is required to recognize a proportional share of Millennium Pipeline's OCI. The remaining unrecognized loss at September 30, 2016 of $23.7 million, before tax, related to terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $23.7 million and $25.0 million, before tax, at September 30, 2016 and December 31, 2015, respectively, is included in gains and losses on cash flow hedges above.

17. Other, Net



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
AFUDC Equity	$	13.8	$	6.6	$	29.7	$	15.0
Miscellaneous	0.5		2.8		0.6		3.6
Total Other, net	$	14.3	$	9.4	$	30.3	$	18.6

18. Supplemental Cash Flow Information

The following table provides additional information regarding the Partnership's Condensed Statements of Consolidated and Combined Cash Flows (unaudited) for the nine months ended September 30, 2016 and 2015:



(in millions)	2016		2015
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities⁽¹⁾	$	211.0	$	218.4
Schedule of interest paid:
Cash paid for interest, net of interest capitalized amounts	$	22.3	$	29.7

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

19. Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for greater than 10% of total operating revenues for the three and nine months ended September 30, 2016 and 2015. The following tables provide this customer's operating revenues and percentage of total operating revenues for the three and nine ended September 30, 2016 and 2015:



Three Months Ended September 30,	2016				2015
(in millions)	Total Operating Revenues		Percentage of Total Operating Revenues		Total Operating Revenues		Percentage of Total Operating Revenues
Columbia Gas of Ohio⁽¹⁾	$	35.6	10.9	%	$	35.3	11.0	%

Nine Months Ended September 30,	2016				2015
(in millions)	Total Operating Revenues		Percentage of Total Operating Revenues		Total Operating Revenues		Percentage of Total Operating Revenues
Columbia Gas of Ohio⁽¹⁾	$	121.1	12.1	%	$	120.4	12.4	%

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

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

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ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

20. Subsequent Events

Distribution. On November 1, 2016, the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period July 1, 2016, through September 30, 2016, of $0.1975 per unit. This distribution is payable on November 18, 2016, to unitholders of record as of November 11, 2016.

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

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

CPG indirectly owns, through its ownership of CEG, 100% of the membership interests in MLP GP. CEG owns all of the subordinated units (“CPPL subordinated units”) representing a 46.5% limited partner interest in CPPL. Pursuant to the merger agreement, Pony Merger Sub will merge with and into CPPL at the effective time of the merger, with CPPL surviving, such that following the merger, MLP GP will remain a wholly owned subsidiary of CPG and the sole general partner of CPPL, and CPG and CEG will be the only limited partners of CPPL. Each CPPL common unit issued and outstanding as of immediately prior to the effective time of the merger will be converted into the right to receive (i) $17.00 per CPPL common unit in cash without any interest thereon plus (ii) an additional amount of cash per CPPL common unit without any interest thereon equal to the product of (x) the number of days from and including the first day of the quarter in which the closing occurs through and including the closing date multiplied by (y) $0.00217 per CPPL common Unit (a daily distribution rate equal to the quotient of $0.1975 divided by ninety-one (91)), plus (iii) an amount equal to $0.1975 per CPPL common unit in cash without any interest thereon if the record date for the CPPL’s quarterly cash distribution with respect to the quarter immediately preceding the quarter in which the closing occurs shall not have occurred prior to the effective time of the merger (the "Merger Consideration"). Incentive distribution rights of CPPL, which are owned by CEG, will be unchanged and remain outstanding as incentive distribution rights of the surviving entity, and no consideration will be delivered in respect thereof. CPPL subordinated units, which are owned by CEG, will also be unchanged and remain outstanding as CPPL subordinated units of the surviving entity, and no consideration will be delivered in respect thereof. CPG will be issued CPPL common units at the effective time of the merger equal to the number of public common units being converted into the right to receive the Merger Consideration. The parties anticipate that the merger will close in the first quarter of 2017 and that CPPL will pay the regular quarterly cash distributions to unitholders at the quarterly per unit distribution rate of $0.1975, with the declaration date and record date for each quarterly distribution to occur no later than 30 days and 42 days, respectively, after the end of each fiscal quarter.

Completion of the merger is conditioned upon, among other things: (1) approval of the merger agreement and the transactions contemplated by the merger agreement, including the merger, by the affirmative vote or consent of holders, as of the record date of the special meeting of CPPL’s unitholders (including CEG), of (a) a majority of the outstanding CPPL common units, voting as a class, (b) a majority of the CPPL common units held by the CPPL unaffiliated unitholders, and (c) a majority of the outstanding CPPL subordinated units, voting as a class; (2) all required filings, consents, approvals, permits and authorizations in connection with the merger having been made or obtained; and (3) the absence of legal injunctions or impediments prohibiting the merger transactions.

Pursuant to the merger agreement, CEG delivered a consent to voting the CPPL subordinated units owned beneficially or of record by it or any of its subsidiaries in favor of the merger proposal, including the 46,811,398 CPPL subordinated units currently held by CEG, which units represent 100% of the outstanding CPPL subordinated units.

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ITEM 1. FINANCIAL STATEMENTS (continued)

Columbia Pipeline Partners LP

Notes to Condensed Consolidated and Combined Financial Statements (unaudited) (continued)

breaching party of written notice from the non-breaching party (a “terminable breach”); (4) CPPL does not obtain the requisite unitholder approval of the merger agreement and the merger transactions at a special meeting of unitholders; or (5) either the GP Board, in accordance with the merger agreement, withdraws, modifies or qualifies, or proposes to publicly withdraw, modify or qualify, in a manner adverse to CPG its recommendation to the unitholders of CPPL (the “CPPL Board Recommendation”) or fails to include the CPPL Board Recommendation in the proxy statement to be filed by CPPL in connection with the merger (that taking of any such action being referred to as a “CPPL Change in Recommendation”).

All costs and expenses incurred in connection with the merger agreement and the merger transactions will be paid by the party incurring such costs and expenses, except that (1) CPG and CPPL shall each bear and pay one half of the expenses incurred in connection with the proxy statement and Schedule 13E-3 filings, (2) if (a) CPG terminates the merger agreement due to a CPPL Change in Recommendation, (b) either party terminates the merger agreement due to the failure to obtain the requisite unitholder approval of the merger agreement and the merger transactions at a special meeting of unitholders of CPPL and prior to such special meeting, a CPPL Change in Recommendation has occurred, or if CPG terminates the merger agreement due to a terminable breach by CPPL, CPPL will pay the expenses incurred by CPG up to a maximum of $10.0 million, and (3) if CPPL terminates the merger agreement due to a terminable breach by CPG, CPG will pay the expenses incurred by CPPL.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Columbia Pipeline Partners LP

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q (this "Form 10-Q") to the “Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a context for periods prior to February 11, 2015, the date on which we closed our IPO, refer to the accounting predecessor to Columbia Pipeline Partners LP. References to “Columbia Pipeline Partners,” “we,” “our,” “us” and the “Partnership” or like terms when used in a context for periods subsequent to the IPO or prospectively, refer to Columbia Pipeline Partners LP and its subsidiaries. We refer to our general partner, CPP GP LLC, as our “general partner” and refer to NiSource Inc. and its subsidiaries as “NiSource.”

This discussion and analysis should be read in conjunction with information contained in our accompanying unaudited consolidated and combined interim financial statements and the notes thereto and our combined financial statements and notes thereto included in our 2015 Form 10-K.

Note regarding forward-looking statements

This Form 10-Q includes certain “forward-looking statements,” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by third-party operators, processors and transporters;


•	the demand for natural gas storage and transportation services;


•	our ability to successfully implement our business plan;


•	our ability to complete internal growth projects on time and on budget;


•	the price and availability of debt and equity financing;


•	capital market performance and other factors that may decrease the value of benefit plan assets


•	the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


•	operating hazards and other risks incidental to transporting, storing and gathering natural gas;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	interest rates;


•	labor relations;


•	large customer defaults;


•	changes in the availability and cost of capital;


•	changes in tax status;

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP


•	the effects of existing and future laws and governmental regulations;


•	the effects of future litigation, including litigation relating to the Merger;


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


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


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


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


•	risks relating to the difficulties in integrating the businesses and management of CPG, including the business and management of CPPL, and TransCanada; and


•	certain factors discussed elsewhere in this Form 10-Q.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please see Item 1A “Risk Factors” in our 2015 Form 10-K and this Form 10-Q. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Merger

On March 17, 2016, CPG entered into a 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 Corporation, a Canadian corporation and the direct parent company of Parent (“TransCanada”). Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016, Merger Sub was merged with and into CPG with CPG surviving the Merger as an indirect, wholly owned subsidiary of TransCanada.

Following the completion of the transaction, TransCanada owns the general partner of the Partnership, all of the Partnership's incentive distribution rights and all of the Partnership's subordinated units, which represent a 46.5% limited partnership interest in the Partnership. As a result, the Partnership is now effectively managed by TransCanada.

Proposed Acquisition

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

plus (iii) an amount equal to $0.1975 per CPPL common unit in cash without any interest thereon if the record date for the CPPL’s quarterly cash distribution with respect to the quarter immediately preceding the quarter in which the closing occurs shall not have occurred prior to the effective time of the merger (the "Merger Consideration"). Incentive distribution rights of CPPL, which are owned by CEG, will be unchanged and remain outstanding as incentive distribution rights of the surviving entity, and no consideration will be delivered in respect thereof. CPPL subordinated units, which are owned by CEG, will also be unchanged and remain outstanding as CPPL subordinated units of the surviving entity, and no consideration will be delivered in respect thereof. CPG will be issued CPPL common units at the effective time of the merger equal to the number of public common units being converted into the right to receive the Merger Consideration. The parties anticipate that the merger will close in the first quarter of 2017 and that CPPL will pay the regular quarterly cash distributions to unitholders at the quarterly per unit distribution rate of $0.1975, with the declaration date and record date for each quarterly distribution to occur no later than 30 days and 42 days, respectively, after the end of each fiscal quarter.

The merger agreement contains provisions granting both CPPL and CPG the right to terminate the merger Agreement for certain reasons, including, among others, if: (1) the merger is not completed on or before August 1, 2017; (2) any governmental authority has issued a final and nonappealable statute, rule, order, decree or regulation enjoining or prohibiting consummation of the merger; (3) under certain conditions, there has been a material breach of any of the representations, warranties, covenants or agreements set forth in the merger agreement by a party to the merger agreement which is not cured within 30 days following receipt by the breaching party of written notice from the non-breaching party (a “terminable breach”); (4) CPPL does not obtain the requisite unitholder approval of the merger agreement and the merger transactions at a special meeting of unitholders; or (5) either the GP Board, in accordance with the merger agreement, withdraws, modifies or qualifies, or proposes to publicly withdraw, modify or qualify, in a manner adverse to CPG its recommendation to the unitholders of CPPL (the “CPPL Board Recommendation”) or fails to include the CPPL Board Recommendation in the proxy statement to be filed by CPPL in connection with the merger (that taking of any such action being referred to as a “CPPL Change in Recommendation”).

All costs and expenses incurred in connection with the merger agreement and the merger transactions will be paid by the party incurring such costs and expenses, except that (1) CPG and CPPL shall each bear and pay one half of the expenses incurred in connection with the proxy statement and Schedule 13E-3 filings, (2) if (a) CPG terminates the merger agreement due to a CPPL Change in Recommendation, (b) either party terminates the merger agreement due to the failure to obtain the requisite unitholder approval of the merger agreement and the merger transactions at a special meeting of unitholders of CPPL and prior to such special meeting, a CPPL Change in Recommendation has occurred, or if CPG terminates the merger agreement due to a terminable breach by CPPL, CPPL will pay the expenses incurred by CPG up to a maximum amount of $10 million, and (3) if CPPL terminates the merger agreement due to a terminable breach by CPG, CPG will pay the expenses incurred by CPPL.

Executive Overview

We are a fee-based, growth-oriented Delaware limited partnership formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets. We closed our IPO on February 11, 2015 of 53,833,107 common units. Please see Note 2, "Initial Public Offering" in the Notes to Condensed Consolidated and Combined Financial Statements (unaudited) for further discussion. Prior to July 1, 2015, CPG was a wholly owned subsidiary of NiSource. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource (the "Separation"). Our parent company, CEG, was contributed to CPG prior to the Separation. Our business and operations are conducted through Columbia OpCo, a recently formed partnership between CEG, our parent company, which is indirectly owned by TransCanada, and us. Our assets consist of a 15.7% limited partner interest in Columbia OpCo, as well as the non-economic general partner interest in Columbia OpCo. Through our ownership of Columbia OpCo’s general partner and our 15.7% limited partner interest,

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

we control all of Columbia OpCo’s assets and operations. As a result of this control and the 15.7% limited partner interest, we consolidate Columbia OpCo and CEG's retained interest of 84.3% is recorded as a noncontrolling interest in our consolidated financial statements.

Columbia OpCo owns substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and an underground natural gas storage system, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the nine months ended September 30, 2016, 95% of Columbia OpCo’s revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of September 30, 2016, these contracts had a weighted average remaining contract life of 4.7 years.

We expect the revenues generated from Columbia OpCo’s businesses will increase as we execute on our significant portfolio of organic growth opportunities.

Commercial Growth and Expansion

We believe that we are well-positioned to attract volumes to our systems through cost-effective capacity expansions. For example, we have recently completed or we are currently undertaking the following expansions (all amounts listed are inclusive of AFUDC, as applicable):


•	Washington County Gathering. A producer has contracted with us to build an approximately 20 mile gas gathering system in southwestern Pennsylvania. The initial project went into service during the third quarter of 2015 and we expect to invest approximately $120 million through 2021.


•	Gibraltar Pipeline Project. We expect to invest approximately $260 million to construct an approximately 1 MMDth/d dry gas header pipeline in southwest Pennsylvania. We expect this to be the first of multiple phases with an initial in-service date in the fourth quarter of 2016, and a final in-service date in the fourth quarter of 2017.


•	Utica Access Project. We invested approximately $50 million to construct 4.7 miles of 24-inch pipeline to provide 205,000 Dth/d of new firm transportation to provide Appalachian production access to liquid trading points on Columbia Gas Transmission's system. This project was placed into service in the fourth quarter of 2016.


•	Millennium Lateral. We intend to invest approximately $20 million through our ownership stake in Millennium Pipeline to construct approximately 8 miles of 16-inch pipeline to a new power plant situated near Wawayanda, New York. This project will provide up to 127,000 Dth/d of new firm capacity and will be placed into service in the second quarter of 2017.


•	Leach XPress. This project will provide approximately 1.5 MMDth/d of capacity from the Marcellus and Utica production regions to the Leach compressor station located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. We expect the project, which involves an estimated investment of $1.4 billion, to be placed into service in the fourth quarter of 2017.

•

Rayne XPress. This project will transport approximately 1 MMDth/d of southwest Marcellus and Utica production on the Columbia Gulf system from the Leach, Kentucky interconnect with Columbia Gas Transmission towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. We expect the project, which involves an estimated investment of $420 million, to be placed into service in the fourth quarter of 2017.


•	Cameron Access Project. This project, which involves an investment of approximately $300 million, will provide 800,000 Dth/d of transportation capacity on the Columbia Gulf system to the Cameron LNG export terminal in Louisiana. We expect the project to be placed into service in the first quarter of 2018.


•	WB XPress. This project, which involves an investment of approximately $0.9 billion, will expand Columbia Gas Transmission's WB system in order to transport approximately 1.3 MMDth/d of Marcellus production to pipeline interconnects and East Coast markets, including access to the Cove Point LNG terminal. We expect this project to be placed into service in the fourth quarter of 2018.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP


•	Mountaineer XPress. This approximately $2.0 billion project will provide new takeaway capacity for Marcellus and Utica production. The project will provide up to 2.7 MMDth/d of firm transportation capacity on the Columbia Gas Transmission system. We expect this project to be placed into service in the fourth quarter of 2018.


•	Gulf XPress. Gulf XPress will provide 860,000 Dth/d of firm transportation capacity for Marcellus and Utica production on the Columbia Gulf system. This project involves an investment of approximately $0.7 billion and is expected to be placed into service in the fourth quarter of 2018.


•	Central Virginia Connector. This project will provide 45,000 Dth/d of firm transportation capacity on the Columbia Gas Transmission system to a new point of delivery in Virginia. This approximately $13 million project is expected to be placed into service in the fourth quarter of 2018.


•	Millennium Eastern System Upgrade. We intend to invest approximately $135 million through our ownership stake in Millennium Pipeline to expand eastward flow capacity by 223,000 Dth/d to Ramapo and other nearby points on the system. We expect this project to be placed into service in the fourth quarter of 2018.

In 2013, the FERC approved the modernization settlement entered into by Columbia Gas Transmission and its customers that provides recovery and return on an investment of up to $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Columbia Gas Transmission placed approximately $320 million in modernization investments into service during 2015. In January 2016, the FERC approved Columbia Gas Transmission's third annual filing for recovery of the revenue requirement under this program. In December 2015, Columbia Gas Transmission filed an extension of this settlement and received the FERC’s approval of the customer agreement in March 2016. This extension will allow Columbia Gas Transmission to invest an additional $1.1 billion over an additional three-year period through 2020. This agreement also expands the scope of facility investments covered by the program.

Items Affecting Comparability of our Financial Results

The historical financial results discussed below may not be comparable to our future financial results for the following reasons:

•

For periods prior to the closing of the IPO on February 11, 2015, the financial statements included in this Form 10-Q were derived from the financial statements and accounting records of the Predecessor. The Predecessor’s results of operations historically included revenues and expenses relating to 100% of NiSource’s Columbia Pipeline Group reportable segment. NiSource did not contribute Crossroads Pipeline Company, CPGSC and Central Kentucky Transmission Company to Columbia OpCo. Such assets were historically included in NiSource’s Columbia Pipeline Group reportable segment, but constituted an immaterial impact on the Predecessor’s results of operations. CNS Microwave is not included in the Predecessor but was contributed to Columbia OpCo.

•

We own a 15.7% interest in Columbia OpCo rather than the 100% ownership reflected as part of the Predecessor’s historical financial results. We control Columbia OpCo through our ownership of its general partner. Our historical financial statements consolidate all of Columbia OpCo’s financial results with ours in accordance with GAAP. Consequently, our consolidated financial statements subsequent to the IPO on February 11, 2015 include Columbia OpCo as a consolidated subsidiary, and CEG’s 84.3% interest is reflected as a noncontrolling interest.


•	We incur incremental annual general and administrative expenses as a result of operating as a publicly traded partnership, which expenses are not reflected in the Predecessor’s financial results for periods prior to our IPO.


•	Upon the closing of the IPO, short-term borrowings-affiliated and a portion of the long-term debt-affiliated (including current portion of long-term debt-affiliated) have been transferred to an affiliate of CPG and the related interest expense is no longer being incurred.

•

We are a limited partnership treated as a partnership for U.S. federal income tax purposes and, therefore, are not liable for entity-level federal income taxes. We are subject to state and local income taxes in certain jurisdictions. The Predecessor’s tax expense was determined on a separate return basis. Accordingly, we expect our tax expense to be significantly reduced subsequent to the IPO as compared to that of the Predecessor.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

•

On June 24, 2016, we entered into a $50.0 million intercompany credit agreement with CEG, with a maturity date of December 31, 2016. Loans under the agreement bear interest at the LIBOR, plus 1.075%. As of September 30, 2016, the Partnership had $5.0 million in outstanding borrowings under the agreement. As a result, we will incur affiliated interest expense on outstanding borrowings under the intercompany credit agreement.

•

We incurred additional costs as a result of the Merger. We incurred $110.4 million of Merger related costs within operation and maintenance and property and other taxes, including employee related expenses of $101.3 million. Additionally, we incurred a Merger related impairment charge of $11.9 million. These costs are included in "Operation and maintenance" and "Impairment of long-lived assets" on the Condensed Statements of Consolidated and Combined Operations (unaudited).

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Results of Operations

Three and Nine Months Ended September 30, 2016

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2016			2015			2016			2015
Operating Revenues
Transportation revenues	$	269.8		$	265.8		$	836.4		$	751.0
Transportation revenues-affiliated	—			—			—			47.1
Storage revenues	48.9			49.5			147.7			122.3
Storage revenues-affiliated	—			—			—			26.2
Other revenues	7.8			4.7			19.1			28.2
Total Operating Revenues	326.5			320.0			1,003.2			974.8
Operating Expenses
Operation and maintenance	152.2			144.9			357.5			392.9
Operation and maintenance-affiliated	116.2			37.4			198.1			112.1
Depreciation and amortization	38.8			33.4			114.1			98.7
Gain on sale of assets	(9.8		)	(39.0		)	(15.8		)	(52.6		)
Impairment of long-lived assets	11.9			0.6			11.9			0.6
Property and other taxes	17.9			15.2			58.9			53.3
Total Operating Expenses	327.2			192.5			724.7			605.0
Equity Earnings in Unconsolidated Affiliates	16.0			15.3			48.1			44.2
Operating Income	15.3			142.8			326.6			414.0
Other Income (Deductions)
Interest expense	(0.3		)	(1.2		)	(2.8		)	(1.2		)
Interest expense-affiliated	(8.4		)	(6.4		)	(22.6		)	(24.1		)
Other, net	14.3			9.4			30.3			18.6
Total Other Income (Deductions), net	5.6			1.8			4.9			(6.7		)
Income before Income Taxes	20.9			144.6			331.5			407.3
Income Taxes	—			—			0.1			23.7
Net Income	20.9			144.6			331.4			$	383.6
Less: Predecessor net income prior to IPO on February 11, 2015	—			—			—			42.7
Net income subsequent to IPO	20.9			144.6			331.4			340.9
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO	18.0			122.6			283.1			289.3
Net income attributable to limited partners subsequent to IPO	$	2.9		$	22.0		$	48.3		$	51.6
Throughput (MMDth)
Columbia Gas Transmission	378.4			284.3			1,298.7			1,096.7
Columbia Gulf	138.9			137.5			408.0			420.5
Total	517.3			421.8			1,706.7			1,517.2

Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

Operating Revenues. Operating revenues were $326.5 million for the third quarter of 2016, an increase of $6.5 million from the same period in 2015. The increase in operating revenues was primarily due to increased demand revenue of $28.6 million largely from the East Side Expansion, Broad Run Connector and Rayne XPress growth projects, and the CCRM. Additionally, there was higher mineral rights royalty revenue of $3.9 million and increased shorter term transportation services of $1.5 million. These increases were partially offset by a decrease of $29.3 million attributable to the recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Operating Expenses. Operating expenses were $327.2 million for the third quarter of 2016, an increase of $134.7 million from the same period in 2015. The increase in operating expenses was primarily due to increased costs related to the Merger of $110.4 million, decreased gains on the sale of assets of $29.2 million, primarily due to conveyances of mineral interests, higher impairment charges of $11.3 million due to the cancellation of IT system upgrades and increased depreciation and amortization of $5.4 million primarily due to higher levels of in-service assets. Additionally, there were increased employee and administrative expenses of $2.8 million and higher outside service costs of $2.3 million. These changes were partially offset by $29.3 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues.

Equity Earnings in Unconsolidated Affiliates. Equity earnings in unconsolidated affiliates were $16.0 million for the third quarter of 2016, an increase of $0.7 million from the same period in 2015. Equity earnings increased primarily due to earnings generated by Millennium Pipeline.

Other Income (Deductions). Other income (deductions) for the third quarter of 2016 increased income by $5.6 million compared to an increase in income of $1.8 million in the same period in 2015. The variance was primarily due to an increase of $7.2 million for the equity portion of AFUDC, partially offset by higher interest expense of $2.1 million due to increased short-term borrowings from the money pool.

Throughput. Throughput totaled 517.3 MMDth for the third quarter of 2016, compared to 421.8 MMDth for the same period in 2015. The increase of 95.5 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Operating Revenues. Operating revenues were $1,003.2 million for the nine months ended September 30, 2016, an increase of $28.4 million from the same period in 2015. The increase in operating revenues was primarily due to increased demand revenue of $99.7 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 $6.1 million. These increases were partially offset by a decrease of $71.1 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 $6.6 million.

Operating Expenses. Operating expenses were $724.7 million for the nine months ended September 30, 2016, an increase of $119.7 million from the same period in 2015. The increase in operating expenses was primarily due to increased costs related to the Merger of $110.4 million, decreased gains on the sale of assets of $36.8 million, primarily due to conveyances of mineral interests, higher depreciation and amortization of $15.4 million and increased property and other taxes of $4.1 million, both primarily due to higher levels of in-service assets. Additionally, there were higher impairment charges of $11.3 million due to the cancellation of IT system upgrades, increased employee and administrative expenses of $9.4 million and higher outside service costs of $6.1 million. These changes were partially offset by $71.1 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and lower maintenance expenses of $3.8 million.

Equity Earnings in Unconsolidated Affiliates. Equity earnings in unconsolidated affiliates were $48.1 million for the nine months ended September 30, 2016, an increase of $3.9 million from the same period in 2015. Equity earnings increased primarily due to earnings generated by Pennant and Millennium Pipeline.

Other Income (Deductions). Other income (deductions) for the nine months ended September 30, 2016 increased income by $4.9 million compared to a reduction in income of $6.7 million in the same period in 2015. The variance was primarily due to an increase in other income of $14.7 million for the equity portion of AFUDC and a decrease in interest expense of $4.6 million due to the repayment of long-term debt, partially offset by a decrease in interest income of $3.5 million and higher interest expense of $2.6 million due to increased short-term borrowings from the money pool.

Income Taxes. The effective income tax rates were zero and 5.8% for the nine months ended September 30, 2016 and 2015, respectively. The change in the overall effective tax rates between 2016 and 2015 was due to post-IPO income that is not subject to income tax at the partnership level.

Throughput. Throughput totaled 1,706.7 MMDth for the nine months ended September 30, 2016, compared to 1,517.2 MMDth for the same period in 2015. The increase of 189.5 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Non-GAAP Financial Measures

We provide below a discussion of certain non-GAAP financial measures that from time to time we provide to investors as additional information in order to supplement our financial statements, which are presented in accordance with GAAP.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less equity earnings in unconsolidated affiliates and other, net. In addition, to the extent transactions occur that are considered unusual, infrequent or not representative of underlying trends, we will remove the effect of these items from Adjusted EBITDA. Examples of these transactions include impairments and expenses related to the Merger. We define Distributable Cash Flow as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP supplemental financial measures that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Management believes that the presentations of Adjusted EBITDA and Distributable Cash Flow will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA or Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA or Distributable Cash Flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA or Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

The following tables present a reconciliation of Adjusted EBITDA and Distributable Cash Flow to the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2016			2015			2016			2015
Net Income	$	20.9		$	144.6		$	331.4		$	383.6
Add:
Interest expense	0.3			1.2			2.8			1.2
Interest expense-affiliated	8.4			6.4			22.6			24.1
Income taxes	—			—			0.1			23.7
Depreciation and amortization	38.8			33.4			114.1			98.7
Impairment of long-lived assets	11.9			0.6			11.9			0.6
Merger costs	110.4			—			110.4			—
Distributions of earnings received from equity investees⁽¹⁾	20.0			16.2			51.0			44.1
Less:
Equity earnings in unconsolidated affiliates⁽¹⁾	16.0			15.3			48.1			44.2
Other, net⁽²⁾	14.3			9.4			30.3			18.6
Adjusted EBITDA	$	180.4		$	177.7		$	565.9		$	513.2
Less:
Adjusted EBITDA attributable to Predecessor prior to IPO	—			—			—			79.4
Adjusted EBITDA attributable to noncontrolling interest in Columbia OpCo subsequent to IPO	152.4			150.2			478.9			366.8
Adjusted EBITDA attributable to Partnership subsequent to IPO	$	28.0		$	27.5		$	87.0		$	67.0

Net Cash Flows from Operating Activities	$	82.3		$	114.0		$	391.4		$	438.9
Interest expense	0.3			1.2			2.8			1.2
Interest expense-affiliated	8.4			6.4			22.6			24.1
Current taxes	—			—			0.1			13.2
Gain on sale of assets	9.8			38.4			15.8			52.0
Merger costs	110.4			—			110.4			—
Other adjustments to operating cash flows	0.4			(3.7		)	(0.7		)	(8.2		)
Changes in assets and liabilities	(31.2		)	21.4			23.5			(8.0		)
Adjusted EBITDA	$	180.4		$	177.7		$	565.9		$	513.2
Less:
Adjusted EBITDA attributable to Predecessor prior to IPO	—			—			—			79.4
Adjusted EBITDA attributable to noncontrolling interest in Columbia OpCo subsequent to IPO	152.4			150.2			478.9			366.8
Adjusted EBITDA attributable to Partnership subsequent to IPO	$	28.0		$	27.5		$	87.0		$	67.0

Adjusted EBITDA	$	180.4		$	177.7		$	565.9		$	513.2
Less:
Interest expense⁽³⁾	8.7			7.6			25.4			25.3
Maintenance capital expenditures⁽⁴⁾	43.4			25.1			96.0			98.5
Separation maintenance capital expenditures⁽⁵⁾	—			4.1			—			1.4
Gain on sale of assets⁽⁶⁾	9.8			39.0			15.8			52.6
Distributable cash flow attributable to Predecessor prior to IPO	—			—			—			67.8
Distributable cash flow attributable to noncontrolling interest subsequent to IPO	108.9			117.2			374.0			276.2
Add:
Proceeds from sales of assets	9.8			36.0			9.9			55.0
Interest income⁽⁷⁾	0.4			4.2			0.7			4.2
Capital (received) costs related to Separation⁽⁸⁾	—			(4.1		)	—			(1.4		)
Distributable Cash Flow	$	19.8		$	20.8		$	65.3		$	49.2

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

⁽¹⁾ These adjustments result in Adjusted EBITDA only including actual cash received from equity investees.

⁽²⁾ Refer to Note 17, "Other, Net" in the Notes to Condensed Consolidated and Combined Financial Statements (unaudited) for additional information.

⁽³⁾ Interest expense consists of interest expense and interest expense-affiliated, net of capitalized amounts including $3.7 million in AFUDC.

⁽⁴⁾ Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

⁽⁵⁾ Separation maintenance capital expenditures are capital expenditures related to the Separation.

⁽⁶⁾ Gain on sale of assets consists primarily of gains on conveyances of mineral rights positions.

⁽⁷⁾ Interest income is primarily composed of income earned on CPPL's lendings to the NiSource Finance money pool prior to the Separation and the CPG money pool subsequent to the Separation.

⁽⁸⁾ Capital costs related to Separation are capital expenditures related to the Separation, offset by $3.8 million cash received, for the nine months ended September 30, 2015, for asset transfers made under common control with CEG related to the Separation, which is included in proceeds from sales of assets.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Liquidity and Capital Resources

Our principal liquidity requirements are to finance our operations, fund capital expenditures, make cash distributions and satisfy our indebtedness obligations. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future.

Our sources of liquidity may include:


•	cash generated from our operations;


•	our $50.0 million CPPL - CEG Intercompany Credit Agreement;


•	cash distributions received from Columbia OpCo;


•	issuances of additional partnership units;


•	debt offerings;


•	borrowing capacity under an intercompany money pool initially with CPG, in which Columbia OpCo and its subsidiaries are participants; and


•	long-term intercompany borrowings.

We believe that cash on hand, cash generated from operations and availability under our credit facility will be adequate to meet our operating needs, our capital and debt service requirements, repayment of principal on our long-term debt and our cash distribution requirements. We believe that future internal growth projects will be funded primarily through borrowings under our credit facility or through issuances of debt and equity securities.

Cash Flow. Net cash from operating activities, net cash used for investing activities and net cash from financing activities for the nine months ended September 30, 2016 and 2015, were as follows:



	Nine Months Ended September 30,
(in millions)	2016			2015
Net cash from operating activities	$	391.4		$	438.9
Net cash used for investing activities	(1,093.5		)	(989.5		)
Net cash from financing activities	631.6			607.0

Operating Activities

Net cash from operating activities for the nine months ended September 30, 2016 was $391.4 million, a decrease of $47.5 million compared to the nine months ended September 30, 2015. The decrease in net cash from operating activities was primarily attributable to the difference in the timing of collection of receivables and the payment of payables and costs associated with the Merger.

Investing Activities

Net cash used for investing activities for the nine months ended September 30, 2016 was $1,093.5 million, an increase of $104.0 million compared to the nine months ended September 30, 2015. Capital expenditures for the nine months ended September 30, 2016 were $1,073.0 million, compared to $775.9 million for the comparable period in 2015. This increase is mainly due to higher spending on various growth projects primarily in the Marcellus and Utica Shale areas and for expenditures under the modernization program. We project 2016 capital expenditures to be approximately $1.5 billion.

Short-term lendings-affiliated for the nine months ended September 30, 2016 were a $19.1 million cash outflow, compared to a $265.3 million cash outflow for the comparable period in 2015. This $246.2 million variance was primarily a result of investing net proceeds from the IPO into the money pool in 2015.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Contributions to equity investees increased $4.8 million compared to the nine months ended September 30, 2015. During the nine months ended September 30, 2016 and 2015, contributions of $6.2 million and $1.4 million, respectively, were made to Millennium Pipeline to fund capital projects.

Proceeds from disposition of assets decreased $45.1 million primarily due to decreased proceeds received on conveyances of mineral rights positions.

Financing Activities

Net cash from financing activities for the nine months ended September 30, 2016 was $631.6 million, an increase of $24.6 million compared to the nine months ended September 30, 2015. The increase in net cash from financing activities was primarily due to increased short-term borrowings from the CPG money pool to fund capital expenditures, in the current year, and the $500.0 million reimbursement of preformation capital expenditures to CEG, in the prior year. This increase was offset by prior year net proceeds of the IPO of $1,168.4 million. Refer to Note 2, “Initial Public Offering,” in the Notes to Condensed Consolidated and Combined Financial Statements (unaudited) for more information.

Intercompany Credit Agreement Amendment. On January 31, 2016, we amended our intercompany credit agreement with CPG to extend the maturity date of the note originating on December 9, 2013 from December 31, 2016 to December 31, 2020. The outstanding borrowings bear interest at a fixed rate of 4.70%.

CPPL - CEG Intercompany Credit Agreement. On June 24, 2016, we entered into a $50.0 million intercompany credit agreement with CEG, with a maturity date of December 31, 2016. Loans under the intercompany credit agreement bear interest at the LIBOR, plus 1.075 percent. As of September 30, 2016, we had $5.0 million in outstanding borrowings under the agreement, with a weighted average interest rate of 1.79%.

Columbia Pipeline Partners LP Credit Agreement. 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, we accelerated the amortization of $1.4 million of deferred costs associated with the revolving credit facility, which are included in interest expense for the nine months ended September 30, 2016.

Columbia OpCo Money Pool Agreement and CPG Credit Agreement. Columbia OpCo and its subsidiaries maintain a money pool arrangement with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. Effective July 1, 2016, in connection with the Merger, the $1,500.0 million CPG revolving credit facility was terminated and replaced by a $2,000.0 million revolving credit facility with US Parent.

CPG Commercial Paper Program. CPG's commercial paper program (the "Program") had a Program limit of up to $1,000.0 million. OpCo GP and Columbia OpCo, together with CEG, 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.

Contractual Obligations. There were no material changes recorded during the nine months ended September 30, 2016 to contractual obligations as of December 31, 2015.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

Other Information

Critical Accounting Policies

Our critical accounting policies are disclosed in the "Critical Accounting Policies" section of our 2015 Form 10-K. There were no significant changes to critical accounting policies for the period ended September 30, 2016.

Recently Issued Accounting Pronouncements

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Columbia Pipeline Partners LP

Qualifying Income Status and Proposed Regulations

Pursuant to Internal Revenue Code Section 7704(c)(2), in order to be treated as a partnership for U.S. federal income tax purposes, more than 90 percent of the income of a partnership must be from certain specified sources, including the exploration, development, mining or production, processing, refining, marketing and transportation of minerals and natural resources. On May 5, 2015, the Treasury Department and the IRS issued the Proposed Regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Proposed Regulations provide rules regarding the Qualifying Income Exception. The IRS has received and is considering numerous comments regarding the scope of the Proposed Regulations and they may consult with industry experts and others to fully understand the matter. However, there is no set time frame for this process and it can take months or years to finalize the proposed new regulations. Although we do not believe, based upon our current operations and language of the proposed regulations, that we will be treated as a corporation for U.S. federal income tax purposes, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for purposes of the qualifying income requirement.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Columbia Pipeline Partners LP

Market Risk Disclosures

For quantitative and qualitative disclosures about market risk, see Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" in our 2015 10-K. Our exposures to market risk have not changed materially since December 31, 2015.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The principal executive officer and principal financial officer of our general partner performed an evaluation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures are effective as of September 30, 2016.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Columbia Pipeline Partners LP

Environmental Litigation

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

Please see Note 15 (“Other Commitments and Contingencies”) to Part I, Item I of this report, which is incorporated by reference into this Part II, Item 1, for a description of the litigation, legal and administrative proceedings and environmental matters.

ITEM 1A. RISK FACTORS

Except as set forth below, there have been no material changes to the risk factors previously disclosed in our 2015 Form 10-K and our 2016 Second Quarter Report on Form 10-Q.

The Merger with CPG may not be consummated even if CPPL Unitholders approve the Merger proposal.

On November 1, 2016, CPPL, CPG, MLP GP and Pony Merger Sub, entered into an agreement and plan of merger (the “Merger Agreement”), pursuant to which CPG has agreed to acquire, for cash, all of the outstanding publicly held common units representing limited partner interests in CPPL (the “Merger”). Upon closing, CPPL will become an indirect wholly owned entity of TransCanada and will cease to be a publicly held partnership.

The Merger Agreement contains conditions, some of which are beyond the parties’ control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring, even though our unitholders may have voted to approve the Merger proposal. We cannot predict with certainty whether and when any of the conditions to the completion of the Merger will be satisfied. Any delay in completing the Merger could cause us not to realize, or delay the realization of, some or all of the benefits that we expect to achieve from the Merger. In addition, we can agree with CPG not to consummate the Merger even if our unitholders approve the Merger proposal and the conditions to the closing of the Merger are otherwise satisfied.

While the Merger Agreement with CPG is in effect, we may be limited in our ability to pursue other attractive business opportunities.

CPG is interested only in acquiring our outstanding publicly held common units and is not interested in selling the CPPL equity interests held by CPG and its subsidiaries or their interest in CPPL. Therefore, even if a proposal or offer to acquire the assets or equity interests of CPPL were to materialize, CPG, which indirectly owns 46.5% of our limited partner interests, would likely decide not to vote or tender its CPPL equity interests in favor of any such transaction and recommend against approval of such transactions by CPPL’s common unitholders.

We have also agreed to refrain from taking certain actions with respect to our business and financial affairs pending completion of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if completion of the Merger is delayed.

In addition to the economic costs associated with pursuing a merger, CPPL’s management continues to devote substantial time and other resources to the proposed transaction and related matters, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, standalone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our business could be adversely affected.

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ITEMS 1A. RISK FACTORS (continued)

Columbia Pipeline Partners LP

Furthermore, the uncertainty surrounding the approval of the Merger proposal may adversely affect our ability to attract and retain qualified personnel. We operate in an industry that currently experiences a high level of competition among different companies for qualified and experienced personnel. The uncertainty relating to the possibility of the Merger may increase the risk that we could experience higher than normal rates of attrition or that we experience increased difficulty in attracting qualified personnel or incur higher expenses to do so. High levels of attrition among the management and employee personnel necessary to operate our business or difficulties or increased expense incurred to replace any personnel who leave, could materially adversely affect our business or results of operations.

If the Merger with CPG does not occur, we will not benefit from the expenses we have incurred in the pursuit of the Merger.

The Merger with CPG may not be completed. If the Merger is not completed, we will have incurred substantial expenses for which no ultimate benefit will have been received by us. We currently expect to incur Merger-related expenses consisting of independent advisory, legal and accounting fees, and financial printing and other related charges, much of which may be incurred even if the Merger is not completed. In addition, if the Merger Agreement is terminated under specified circumstances, we will be required to pay certain Merger-related expenses of CPG.

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

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

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

Failure to complete, or significant delays in completing, the Merger with CPG could negatively affect the trading prices of our common units and our future business and financial results.

Completion of the Merger is not assured and is subject to risks, including the risks that approval of the Merger by our common unitholders is not obtained or that other closing conditions are not satisfied. If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of our common units and our future business and financial results could be negatively affected, and we will be subject to several risks, including the following:


•	we may be liable for damages to CPG under the terms and conditions of the Merger Agreement;


•	negative reactions from the financial markets, including declines in the prices of our common units due to the fact that current prices may reflect a market assumption that the Merger will be completed;


•	having to pay certain significant costs relating to the Merger; and


•	the attention of our management will have been diverted to the Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

The Merger with CPG is a taxable transaction and the resulting tax liability of a CPPL unitholder, if any, will depend on each such CPPL unitholder’s particular situation.

The receipt of cash as Merger consideration in exchange for our common units in the Merger will be treated as a taxable sale by such common unitholders of such common units for U.S. federal income tax purposes. The amount and character of gain or loss recognized by each unitholder in the Merger will vary depending on each unitholder’s particular situation, including the value of the amount of cash received by each unitholder as Merger consideration in the Merger, the adjusted tax basis of the common units exchanged by each unitholder in the Merger, and the amount of any suspended passive losses that may be available to a particular unitholder to offset a portion of the gain recognized by the unitholder.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

Columbia Pipeline Partners LP

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.




(2.1)	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)	Certificate of Limited Partnership of NiSource Energy Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on September 29, 2014).

(3.2)	Certificate of Amendment to Certificate of Limited Partnership of NiSource Energy Partners, L.P. (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-198990) filed on November 12, 2014).

(3.3)	Second Amended and Restated Agreement of Limited Partnership of Columbia Pipeline Partners LP, dated as of July 30, 2015. (Incorporated by reference to Exhibit 3.3 of the Partnership’s Quarterly Report on Form 10-Q (File No. 001-36835) filed on August 3, 2015).

(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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SIGNATURE

Columbia Pipeline Partners LP

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



			Columbia Pipeline Partners LP
			(Registrant)

		By:	CPP GP LLC, its general partner

Date:	November 1, 2016	By:	/s/ Nathaniel A. Brown
			Nathaniel A. Brown
			Controller and Principal Financial Officer (Principal Accounting Officer and Duly Authorized Officer)

Columbia Pipeline Partners LP - FORM 10-Q - November 1, 2016

Attached files

Columbia Pipeline Partners LP Reports