Columbia Pipeline Partners (CPPL) 10-K 18 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 10, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Registrant Name	COLUMBIA PIPELINE PARTNERS LP/DE
Entity Central Index Key	1,420,783
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,353,717,666
Common Units
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		53,834,784
Subordinated Units
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		46,811,398

Statements of Consolidated and

Statements of Consolidated and Combined Balance Sheets - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents		$ 78.9
Accounts receivable (less reserve of $0.3 and $0.3, respectively)		145.9
Accounts Receivable-affiliated		149.4
Materials and supplies, at average cost		32.8
Exchange gas receivable		18.8
Deferred Property Taxes		52
Deferred income taxes		0
Prepayments and other		33.8
Total Current Assets		511.6
Investments
Unconsolidated affiliates		437.1
Other investments		1.8
Total Investments		438.9
Property, Plant and Equipment
Property, plant and equipment		8,930.9
Accumulated depreciation and amortization		(2,960.1)
Net Property, Plant and Equipment		5,970.8
Other Noncurrent Assets
Regulatory assets		134.1
Goodwill		1,975.5
Postretirement and postemployment benefits assets		120.5
Deferred charges and other		10.6
Total Other Noncurrent Assets		2,240.7
Total Assets		9,162
Current Liabilities
Current portion of long-term debt-affiliated		0
Short-term borrowings		15
Short-term borrowings-affiliated		42.1
Accounts payable		49.9
Accounts payable-affiliated		86.3
Customer deposits		17.8
Taxes accrued		108.2
Exchange gas payable		18.2
Deferred revenue		15
Accrued capital expenditures		95.9
Accrued compensation and related costs		26.6
Other accruals		43.8
Total Current Liabilities		518.8
Noncurrent Liabilities
Long-term debt-affiliated		630.9
Deferred income taxes		1
Accrued liability for postretirement and postemployment benefits		36.1
Regulatory liabilities		309.7
Asset retirement obligations		25.3	$ 23.2
Other noncurrent liabilities		63.5
Total Noncurrent Liabilities		1,066.5
Total Liabilities		1,585.3
Equity and Partners' Capital
Net parent investment		0
Accumulated other comprehensive loss	[1]	(4)
Total Columbia Pipeline Partners LP partners' equity and capital		1,258.5
Noncontrolling Interest in Columbia OpCo		6,318.2
Total Equity and Partners' Capital		7,576.7	4,171.3
Total Liabilities and Equity and Partners' Capital		9,162
Predecessor
Current Assets
Cash and cash equivalents			0.5
Accounts receivable (less reserve of $0.3 and $0.3, respectively)			149.3
Accounts Receivable-affiliated			153.8
Materials and supplies, at average cost			24.9
Exchange gas receivable			34.8
Deferred Property Taxes			48.9
Deferred income taxes			24.6
Prepayments and other			20.9
Total Current Assets			457.7
Investments
Unconsolidated affiliates			444.3
Other investments			6.2
Total Investments			450.5
Property, Plant and Equipment
Property, plant and equipment			7,931.6
Accumulated depreciation and amortization			(2,971.4)
Net Property, Plant and Equipment			4,960.2
Other Noncurrent Assets
Regulatory assets			151.9
Goodwill			1,975.5
Postretirement and postemployment benefits assets			102.7
Deferred charges and other			9
Total Other Noncurrent Assets			2,239.1
Total Assets			8,107.5
Current Liabilities
Current portion of long-term debt-affiliated			115.9
Short-term borrowings			0
Short-term borrowings-affiliated			247.3
Accounts payable			56.1
Accounts payable-affiliated			49.9
Customer deposits			13.4
Taxes accrued			106.9
Exchange gas payable			34.7
Deferred revenue			22.2
Accrued capital expenditures			61.1
Accrued compensation and related costs			31.2
Other accruals			39
Total Current Liabilities			777.7
Noncurrent Liabilities
Long-term debt-affiliated			1,472.8
Deferred income taxes			1,239
Accrued liability for postretirement and postemployment benefits			44.7
Regulatory liabilities			294.3
Asset retirement obligations			23.2
Other noncurrent liabilities			84.5
Total Noncurrent Liabilities			3,158.5
Total Liabilities			3,936.2
Equity and Partners' Capital
Net parent investment			4,188
Accumulated other comprehensive loss	[1]		(16.7)
Total Columbia Pipeline Partners LP partners' equity and capital			4,171.3
Noncontrolling Interest in Columbia OpCo			0
Total Equity and Partners' Capital			4,171.3
Total Liabilities and Equity and Partners' Capital			8,107.5
Common Units
Equity and Partners' Capital
Limited Partners' Capital Account		958.5
Common Units | Predecessor
Equity and Partners' Capital
Limited Partners' Capital Account			0
Subordinated Units
Equity and Partners' Capital
Limited Partners' Capital Account		$ 304
Subordinated Units | Predecessor
Equity and Partners' Capital
Limited Partners' Capital Account			$ 0
[1]	All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated and3

Statements of Consolidated and Combined Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts receivable less reserve	$ 0.3
Predecessor
Accounts receivable less reserve		$ 0.3
Common Units
Limited Partners' Capital Account, Units Issued	53,834,784
Limited Partners' Capital Account, Units Outstanding	53,834,784
Common Units | Predecessor
Limited Partners' Capital Account, Units Issued	0
Limited Partners' Capital Account, Units Outstanding	0
Subordinated Units
Limited Partners' Capital Account, Units Issued	46,811,398
Limited Partners' Capital Account, Units Outstanding	46,811,398
Subordinated Units | Predecessor
Limited Partners' Capital Account, Units Issued	0
Limited Partners' Capital Account, Units Outstanding	0

Statements Of Consolidated and4

Statements Of Consolidated and Combined Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues
Transportation revenues	$ 1,052.2
Transportation revenues-affiliated	47.1
Storage revenues	171.4
Storage revenues-affiliated	26.2
Other revenues	34.9
Total Operating Revenues	1,331.8
Operating Expenses
Operation and maintenance	526.1
Operating and maintenance-affiliated	164.1
Depreciation and amortization	135
Gain (Loss) on Disposition of Assets	(54.7)
Property and other taxes	71.2
Total Operating Expenses	841.7
Equity Earnings in Unconsolidated Affiliates	60.2
Operating Income	550.3
Other Income (Deductions)
Interest expense	(1.4)
Interest expense-affiliated	(26.8)
Other, net	32
Total Other Income (Deductions), net	3.8
Income before Income Taxes	554.1
Income Taxes	23.9
Net Income	530.2
Income (Loss), Including Portion Attributable to Noncontrolling Interest	530.2
Less: Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO	413.5
Net income attributable to controlling interest subsequent to IPO	$ 74
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 0.74
Weighted average limited partner units outstanding (basic and diluted)
Weighted Average Number of Shares Outstanding, Basic and Diluted	100.6
Predecessor
Operating Revenues
Transportation revenues		$ 990.9	$ 850.9
Transportation revenues-affiliated		95.8	94.3
Storage revenues		144	142.8
Storage revenues-affiliated		53.2	53.6
Other revenues		63	37.8
Total Operating Revenues		1,346.9	1,179.4
Operating Expenses
Operation and maintenance		630.7	507.1
Operating and maintenance-affiliated		122.9	118.1
Depreciation and amortization		118.6	106.9
Gain (Loss) on Disposition of Assets		(34.5)	(18.6)
Property and other taxes		67.1	62.2
Total Operating Expenses		904.8	775.7
Equity Earnings in Unconsolidated Affiliates		46.6	35.9
Operating Income		488.7	439.6
Other Income (Deductions)
Interest expense		0	0
Interest expense-affiliated		(62)	(37.9)
Other, net		8.8	17.6
Total Other Income (Deductions), net		(53.2)	(20.3)
Income before Income Taxes		435.5	419.3
Income Taxes		166.4	152.4
Net Income		269.1	266.9
Income (Loss), Including Portion Attributable to Noncontrolling Interest		$ 269.1	$ 266.9
Common Units
Other Income (Deductions)
Net income attributable to controlling interest subsequent to IPO	$ 39.6
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 0.74
Weighted average limited partner units outstanding (basic and diluted)
Weighted Average Number of Shares Outstanding, Basic and Diluted	53.8
Subordinated Units
Other Income (Deductions)
Net income attributable to controlling interest subsequent to IPO	$ 33.8
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 0.72
Weighted average limited partner units outstanding (basic and diluted)
Weighted Average Number of Shares Outstanding, Basic and Diluted	46.8

Statements of Consolidated and5

Statements of Consolidated and Combined Comprehensive Income - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
		Feb. 11, 2015	Dec. 31, 2015	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Net Income		$ 42.7	$ 487.5	$ 530.2
Net unrealized gain on cash flow hedges	[1]			1.5
Unrecognized pension and OPEB costs	[2]			(0.2)
Other Comprehensive Income, Net of Tax and Transaction Adjustments				1.3
Total comprehensive income		42.8	488.7	531.5
Total comprehensive income		$ 0.1	1.2	$ 1.3	[3]
Less: Comprehensive income attributable to noncontrolling interest subsequent to IPO			414.5
Comprehensive income attributable to limited partners subsequent to IPO			$ 74.2
Predecessor
Net Income						$ 269.1	$ 266.9
Net unrealized gain on cash flow hedges	[1]					1	1.1
Unrecognized pension and OPEB costs	[2]					0	0
Other Comprehensive Income, Net of Tax and Transaction Adjustments						1	1.1
Total comprehensive income						270.1	268
Total comprehensive income	[3]					$ 1	$ 1.1
[1]	Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.1 million, $0.7 million and $0.6 million tax expense in 2015, 2014 and 2013, respectively.
[2]	Unrecognized pension and OPEB costs, net of zero tax expense in 2015, 2014 and 2013, respectively.
[3]	All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits.

Statements of Consolidated and6

Statements of Consolidated and Combined Comprehensive Income Statements of Consolidated and Combined Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive (Income) Loss, Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 0.1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax	$ 0
Predecessor
Other Comprehensive (Income) Loss, Unrealized Gain (Loss) on Derivatives Arising During Period, Tax		$ 0.7	$ 0.6
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax		$ 0	$ 0

Statements Of Consolidated and7

Statements Of Consolidated and Combined Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income	$ 530.2
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization	135
Deferred income taxes and investment tax credits	10.5
Deferred revenue	4.2
Equity-based compensation expense and profit sharing contribution	5.6
Gain on sale of assets and impairment, net	(54.7)
Equity earnings in unconsolidated affiliates	(60.2)
Amortization of debt related costs	0.4
AFUDC equity	(28.3)
Distributions of earnings received from equity investees	57.2
Accounts receivable	(11)
Accounts receivable-affiliated	21.6
Accounts payable	(10)
Accounts payable-affiliated	30.1
Customer deposits	(22.9)
Taxes accrued	19.5
Exchange gas receivable/payable	0
Other accruals	10.5
Prepayments and other current assets	(13.5)
Regulatory assets/liabilities	27.6
Postretirement and postemployment benefits	(5.2)
Deferred charges and other noncurrent assets	(13.8)
Other noncurrent liabilities	(5.1)
Net Cash Flows from Operating Activities	627.7
Investing Activities
Capital expenditures	(1,106.6)
Insurance recoveries	2.1
Changes in short-term lendings-affiliated	(24.3)
Proceeds from disposition of assets	84.1
Contributions to equity investees	(1.4)
Distributions from equity investees	16
Other investing activities	(22.4)
Net Cash Flows used for Investing Activities	(1,052.5)
Financing Activities
Change in short-term borrowings-affiliated	15
Change in short-term borrowings-affiliated	(207.2)
Issuance of long-term debt-affiliated	0
Payments of long-term debt-affiliated, including current portion	(959.6)
Proceeds from issuance of common units, net of offering costs	1,168.4
Distribution of IPO proceeds to parent	500
Contribution of capital from parent	(1,217.3)
Distribution to parent	0
Quarterly distributions to unitholders	43.4
Distribution to noncontrolling interest in Columbia OpCo	187.3
Net Cash Flows from Financing Activities	503.2
Change in cash and cash equivalents	78.4
Cash and cash equivalents at beginning of period	78.9
Predecessor
Net Income		$ 269.1	$ 266.9
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization		118.6	106.9
Deferred income taxes and investment tax credits		139.3	179.9
Deferred revenue		1.6	(0.5)
Equity-based compensation expense and profit sharing contribution		6.3	2.2
Gain on sale of assets and impairment, net		(34.5)	(18.6)
Equity earnings in unconsolidated affiliates		(46.6)	(35.9)
Amortization of debt related costs		0	0
AFUDC equity		(11)	(6.8)
Distributions of earnings received from equity investees		37.8	32.1
Accounts receivable		(20.3)	2.5
Accounts receivable-affiliated		2.2	(7.6)
Accounts payable		2.8	5.5
Accounts payable-affiliated		8.6	16.3
Customer deposits		77.5	1.3
Taxes accrued		11.8	(28.5)
Exchange gas receivable/payable		1.1	(0.5)
Other accruals		0.6	0.4
Prepayments and other current assets		(4.4)	21.7
Regulatory assets/liabilities		9	42.6
Postretirement and postemployment benefits		2.2	(113.3)
Deferred charges and other noncurrent assets		(4.3)	2.5
Other noncurrent liabilities		0.7	(15.1)
Net Cash Flows from Operating Activities		568.1	454
Investing Activities
Capital expenditures		(747.2)	(674.8)
Insurance recoveries		11.3	6.4
Changes in short-term lendings-affiliated		(61.6)	(10)
Proceeds from disposition of assets		9.3	15.4
Contributions to equity investees		(69.2)	(125.5)
Distributions from equity investees		0	0
Other investing activities		(7.1)	(8.9)
Net Cash Flows used for Investing Activities		(864.5)	(797.4)
Financing Activities
Change in short-term borrowings-affiliated		0	0
Change in short-term borrowings-affiliated		(472.3)	391
Issuance of long-term debt-affiliated		768.9	65.1
Payments of long-term debt-affiliated, including current portion		0	0
Proceeds from issuance of common units, net of offering costs		0	0
Distribution of IPO proceeds to parent		0	0
Contribution of capital from parent		0	0
Distribution to parent		0	(113)
Quarterly distributions to unitholders		0	0
Distribution to noncontrolling interest in Columbia OpCo		0	0
Net Cash Flows from Financing Activities		296.6	343.1
Change in cash and cash equivalents		0.2	(0.3)
Cash and cash equivalents at beginning of period	$ 0.5	0.3	0.6
Cash and cash equivalents at beginning of period		$ 0.5	$ 0.3

Statements Of Consolidated and8

Statements Of Consolidated and Combined Equity and Partners' Capital - USD ($) $ in Millions		Total	Parent	Noncontrolling Interest	Accumulated Other Comprehensive Loss	Limited Partner	Limited PartnerCommon Units	Limited PartnerSubordinated Units
Beginning Balance (Predecessor) at Dec. 31, 2012			$ 3,758.3
Beginning Balance at Dec. 31, 2012		$ 3,739.5		$ 0	$ (18.8)		$ 0	$ 0
Net Income (Loss) Attributable to Parent | Predecessor			266.9
Net Income (Loss) Attributable to Parent		266.9		0	0		0	0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | Predecessor			0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent		1.1		0	1.1		0	0
Partners' Capital Account, Distributions | Predecessor			(113)
Partners' Capital Account, Distributions		(113)		0	0	$ 0	0
Net Transfers (To) From Parent | Predecessor			5.4
Net Transfers (To) From Parent		5.4		0	0		0	0
Net Income | Predecessor		266.9
Total comprehensive income | Predecessor	[1]	1.1
Ending Balance (Predecessor) at Dec. 31, 2013			3,917.6
Ending Balance at Dec. 31, 2013		3,899.9		0	(17.7)		0	0
Net Income (Loss) Attributable to Parent | Predecessor			269.1
Net Income (Loss) Attributable to Parent		269.1		0	0		0	0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | Predecessor			0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent		1		0	1		0	0
Net Transfers (To) From Parent | Predecessor			1.3
Net Transfers (To) From Parent		1.3		0	0		0	0
Net Income | Predecessor		269.1
Total comprehensive income | Predecessor	[1]	1
Ending Balance (Predecessor) at Dec. 31, 2014		4,171.3	4,188
Ending Balance at Dec. 31, 2014		4,171.3		0	(16.7)		0	0
Net Income | Predecessor			42.7
Net Income		42.7		0	0		0	0
Total comprehensive income | Predecessor			0
Total comprehensive income		0.1		0	0.1		0	0
Contribution of capital from parent | Predecessor			1,217.3
Contribution of capital from parent		1,217.3		0	0		0	0
Predecessor Net Liabilities Not Assumed By Subsidiary | Predecessor			1,232.5
Predecessor Net Liabilities Not Assumed By Subsidiary		1,222.2		0	(10.3)		0	0
Contributed/Noncontributed Net Parent Investment Adjustments | Predecessor			(7.7)
Contributed/Noncontributed Net Parent Investment Adjustments		(7.7)		0	0		0	0
Ending Balance (Predecessor) at Feb. 11, 2015			6,672.8
Ending Balance at Feb. 11, 2015		6,645.9		0	(26.9)		0	0
Beginning Balance (Predecessor) at Dec. 31, 2014		4,171.3	4,188
Beginning Balance at Dec. 31, 2014		4,171.3		0	(16.7)		0	0
Net Income		530.2
Total comprehensive income	[1]	1.3
Predecessor Net Liabilities Not Assumed By Subsidiary	[1],[2]				(10.3)
Ending Balance (Predecessor) at Dec. 31, 2015			0
Ending Balance at Dec. 31, 2015		7,576.7		6,318.2	(4)		958.5	304
Beginning Balance (Predecessor) at Feb. 11, 2015			6,672.8
Beginning Balance at Feb. 11, 2015		6,645.9		0	(26.9)		0	0
Net Transfers (To) From Parent | Predecessor			0
Net Transfers (To) From Parent		4.4		3.6	0		0.5	0.3
Net Income | Predecessor			0
Net Income		487.5		413.5	0		39.9	34.1
Total comprehensive income | Predecessor			0
Total comprehensive income		1.2		1	0.2		0	0
Allocation of Net Investment to Unitholders | Predecessor			(6,672.8)
Allocation of Net Investment to Unitholders		0		6,185.7	0		0	487.1
Allocation of Accumulated Other Comprehensive Loss To Noncontrolling Interest | Predecessor			0
Allocation of Accumulated Other Comprehensive Loss To Noncontrolling Interest		0		(22.7)	22.7		0	0
Net proceeds from IPO | Predecessor			0
Net proceeds from IPO		1,168.4		0	0		1,168.4	0
Purchase of additional interest in Columbia OpCo | Predecessor			0
Purchase of additional interest in Columbia OpCo		0		424.4	0		(227.1)	(197.3)
Distribution to the noncontrolling interest in Columbia OpCo | Predecessor			0
Distribution to the noncontrolling interest in Columbia OpCo		(687.3)		(687.3)	0		0	0
Limited Partners' Capital Account, Distribution Amount | Predecessor			0
Limited Partners' Capital Account, Distribution Amount		(43.4)		0	0		(23.2)	(20.2)
Ending Balance (Predecessor) at Dec. 31, 2015			$ 0
Ending Balance at Dec. 31, 2015		$ 7,576.7		$ 6,318.2	$ (4)		$ 958.5	$ 304
[1]	All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits.
[2]	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.

Statements Of Consolidated and9

Statements Of Consolidated and Combined Equity and Partners' Capital (Parenthetical) $ in Millions	11 Months Ended
	Dec. 31, 2015USD ($)
Net proceeds from IPO	$ 1,168.4
Hardy Storage
Equity Method Investment, Percent Not Contributed to Partnership	1.00%
Equity Method Investment, Ownership Percentage	49.00%
Columbia OpCo
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest Additional Ownership Interest	8.40%
Limited Partner | Common Units
Net proceeds from IPO	$ 1,168.4

Nature of Operations And Summar

Nature of Operations And Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Nature of Operations And Summary of Significant Accounting Policies [Abstract]
Significant Accounting Policies	Nature of Operations and Summary of Significant Accounting Policies A. Company Structure and Basis of Presentation . Columbia Pipeline Partners LP (the "Partnership") was formed in Delaware on December 5, 2007, as a subsidiary of NiSource Inc. ("NiSource"). 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. 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 that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under 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. As a result of this control and the 15.7% limited partner interest, the Partnership 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 annual 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 annual report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows: • The Consolidated and Combined Balance Sheets consist of the consolidated balance sheet of the Partnership as of December 31, 2015 and the combined balance sheet of the Predecessor as of December 31, 2014 . • The Statements of Consolidated and Combined Operations consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Comprehensive Income consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Cash Flows consist of the consolidated cash flows of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined cash flows of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Equity and Partners' Capital consist of the consolidated activity of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined activity of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . The Partnership’s accompanying Consolidated and Combined Financial Statements have been prepared in accordance with GAAP. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream, CEVCO, CNS Microwave, OpCo GP, Columbia OpCo and the Partnership. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline, and Pennant. All intercompany transactions and balances have been eliminated. B. Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. C. Cash and Cash Equivalents . Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months. D. Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is the Partnership's best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. E. Basis of Accounting for Rate-Regulated Subsidiaries . Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated and Combined Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. In the event that regulation significantly changes the opportunity for the Partnership to recover its costs in the future, all or a portion of the Partnership’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of the Partnership’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of regulatory accounting, the Partnership would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, the Partnership’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 12, "Regulatory Matters," in the Notes to Consolidated and Combined Financial Statements for further discussion. F. Property, Plant and Equipment and Related AFUDC and Maintenance . Property, plant and equipment is stated at cost. The Partnership's rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. The Partnership's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties. The Partnership capitalizes AFUDC on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and ADUFC equity are summarized in the table below: 2015 2014 2013 Debt Equity Debt Equity Debt Equity Predecessor Predecessor Columbia Gas Transmission 1.8 % 6.3 % 0.9 % 3.0 % 2.5 % 3.2 % Columbia Gulf 2.9 % 6.3 % 2.1 % 9.4 % 2.5 % 3.2 % The Partnership follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation. G. Gas Stored-Base Gas. Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were no purchases of base gas during the years ended December 31, 2015 , 2014 and 2013 . Please see Note 8, "Gain on Sale of Assets," in the Notes to Consolidated and Combined Financial Statements for information regarding the sale of storage base gas in 2013 . Gas stored-base gas is included in Property, plant and equipment on the Consolidated and Combined Balance Sheets. H. Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. The Partnership amortized $5.8 million in 2015 , $4.3 million in 2014 and $5.0 million in 2013 related to software costs. The Partnership’s unamortized software balance was $27.1 million and $18.3 million at December 31, 2015 and 2014 , respectively. I. Goodwill. The Partnership has $1,975.5 million in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the CEG acquisition on November 1, 2000. Please see Note 10, "Goodwill," in the Notes to Consolidated and Combined Financial Statements for further discussion. J. Impairments. An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long-lived assets is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long-lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. The Partnership recognized an impairment loss of $0.6 million for the year ended December 31, 2015 and zero for the years ended December 31, 2014 and 2013 . K. Revenue Recognition. Revenue is recorded as services are performed. Revenues are billed to customers monthly at rates established through the FERC's cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed. The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues for both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. The Partnership provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided. Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage. The Partnership includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realized. Royalty revenue was $26.5 million , $43.8 million and $21.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations. The Partnership periodically recognizes gains on the conveyance of mineral interest related to pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if the Partnership has a substantial obligation for future performance. As the obligation for future performance is satisfied, the deferred revenue is relieved and the associated gain is recognized. Gains on conveyances amounted to $52.3 million , $34.5 million and $7.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations. L. Estimated Rate Refunds . The Partnership collects revenue subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome. M. Accounting for Exchange and Balancing Arrangements of Natural Gas. The Partnership enters into balancing and exchange arrangements of natural gas as part of its operations. The Partnership records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on the Partnership’s Consolidated and Combined Balance Sheets, as appropriate. N. Income Taxes and Investment Tax Credits. 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. The Predecessor's operating results were included in NiSource's consolidated U.S. federal and in consolidated, combined or stand-alone state income tax returns. Amounts presented in the combined financial statements prior to the IPO relate to income taxes that have been determined on a separate tax return basis, and the Predecessor's contribution to NiSource's net operating losses and tax credits have been included in the Predecessor's financial statements. O. Environmental Expenditures. The Partnership accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The reserves for estimated environmental expenditures are recorded on the Consolidated and Combined Balance Sheets in “Other Accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. The Partnership establishes regulatory assets on the Consolidated and Combined Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 17, "Other Commitments and Contingencies" in the Notes to Consolidated and Combined Financial Statements for further discussion. P. Accounting for Investments. The Partnership accounts for its ownership interests in Millennium Pipeline using the equity method of accounting. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where the Partnership (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence. The Partnership has a 49% interest in Hardy Storage. The Predecessor had a 50% interest in Hardy Storage. The Partnership and the Predecessor reflect the investment in Hardy Storage as an equity method investment. Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. During the third quarter of 2015, an additional member, an affiliate of Williams Partners, joined the Pennant joint venture. Williams Partners' initial ownership investment in Pennant is 5.00% , and by funding specified investment amounts for future growth projects, Williams Partners can invest directly in the growth of Pennant. Such funding will potentially increase Williams Partners' ownership in Pennant up to 33.33% over a defined investment period. As a result of the buy-in, Columbia Midstream received $12.7 million in cash and recorded a gain of $2.9 million , and its ownership interest in Pennant decreased from 50.0% to 47.5% . The Partnership accounts for the joint venture under the equity method of accounting. Q. Natural Gas and Oil Properties. CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method. CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015 and 2014 : (in millions) 2015 2014 Beginning Balance $ 14.9 $ 1.9 Additions pending the determination of proved reserves 1.3 20.1 Reclassifications of proved properties (14.5 ) (7.1 ) Ending Balance $ 1.7 $ 14.9 As of December 31, 2015 , there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to one project initiated in 2013 .

Initial Public Offering

Initial Public Offering	12 Months Ended
	Dec. 31, 2015
Initial Public Offering [Abstract]
Initial Public Offering	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 offering 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 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; The table below summarizes the effects of the changes in the Partnership's ownership interest in Columbia OpCo on the Partnership's equity: Year Ended December 31, (in millions) 2015 Net income attributable to the Partnership $ 74.0 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 $ (350.4 ) • 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.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recent Accounting Pronouncements	Recent Accounting Pronouncements 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 is required to adopt ASU 2015-03 and ASU 2015-15 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively with early adoption permitted. The Partnership does not anticipate the adoption of ASU 2015-03 and ASU 2015-15 will have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2017, including interim periods, and the new standard is to be applied retrospectively with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. The Partnership is currently evaluating the impact the adoption of ASU 2014-09 and ASU 2015-14 will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements. 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 is required to adopt ASU 2015-06 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively, with early adoption permitted. The Partnership does not anticipate the adoption of ASU 2015-06 will have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. The Partnership is required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. The Partnership is currently evaluating the impact the adoption of ASU 2015-02 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate that the impact will be material.

Partners' Equity and Cash Distr

Partners' Equity and Cash Distributions	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Partners' Equity And Cash Distribution	Partners' Equity and Cash Distributions Common Unit. As described below, the common unitholders have preference over subordinated unitholders on receipt of distributions, including, in certain circumstances, cash distributions upon liquidation, as set out in the Partnership's Second Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement"). The common unitholders have limited rights on matters affecting Partnership's business, limited voting rights and are not entitled to elect the general partner or its directors. Subordinated Unit. The subordinated unitholders have similar rights as the common unitholders. However, during the subordination period, the subordinated unitholders are not entitled to receive quarterly distributions from operating surplus until the common unitholders have received the minimum quarterly distribution from operating surplus and, among other things, in certain circumstances, are subordinated in the receipt of cash distributions upon liquidation. The subordination period will end on the first business day after the Partnership has earned and paid an aggregate amount of at least the minimum quarterly distribution multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2018 and there are no outstanding arrearages on the Partnership's common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least 150.0% of the minimum quarterly distribution on an annualized basis multiplied by the total number of outstanding common and subordinated units and have earned that amount plus the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2016 and there are no outstanding arrearages on the Partnership's common units. Incentive Distribution Rights. The Partnership Agreement generally provides that the Partnership will distribute cash each quarter during the subordination period in the following manner: first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.192625 , plus any arrearages from prior quarters; second, 85.0% to the holders of common and subordinated units, pro rata, and 15.0% to CEG as the holder of the incentive distribution rights, until each unitholder has received the minimum quarterly distribution of $0.209375 ; and third, 75.0% to the holders of common and subordinated units, pro rata, and 25.0% to CEG as the holder of the incentive distribution rights, until each unitholder has received a distribution of $0.251250 . If cash distributions to the Partnership's unitholders exceed $0.251250 per common unit and subordinated unit in any quarter, the Partnership will distribute 50.0% to the holders of common and subordinated units, pro rata, and 50.0% to CEG as the holder of the incentive distribution rights. The Partnership has paid or has authorized payment of the following quarterly cash distributions under the Partnership Agreement during 2015: (in millions, except per unit amounts) Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2015 (1) May 13, 2015 May 20, 2015 $ 0.0912 $ 9.2 June 30, 2015 August 13, 2015 August 20, 2015 0.1675 16.9 September 30, 2015 November 13, 2015 November 20, 2015 0.1725 17.4 December 31, 2015 February 11, 2016 February 19, 2016 0.1800 18.1 (1) The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income Per Limited Partner Unit	Net Income Per Limited Partner Unit The Partnership computes earnings per unit using the two-class method for Master Limited Partnerships. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. The Partnership calculates net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the Partnership Agreement and as further prescribed by ASC 260 under the two-class method. The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights holder under the terms of the Partnership Agreement, even though we make distributions on the basis of available cash and not earnings. 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. 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 units 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 January 29, 2016 , the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period October 1, 2015 , through December 31, 2015 , of $0.1800 per unit, or $18.1 million in total. This distribution is payable on February 19, 2016 , to unit holders of record as of February 11, 2016 . The calculation of net income per unit is as follows: Year Ended December 31, 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 $ 32.9 $ 28.7 $ — $ 61.6 Net income in excess of distribution (1) 6.7 5.1 0.6 12.4 Net income attributable to partners $ 39.6 $ 33.8 $ 0.6 $ 74.0 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 $ 0.74 $ 0.72 $ 0.74 (1) Net income attributable to partners in excess of distribution is for the period subsequent to the IPO.

Transactions With Affiliates

Transactions With Affiliates	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Transactions With Affiliates	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 Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Transportation revenues $ 47.1 $ 95.8 $ 94.3 Storage revenues 26.2 53.2 53.6 Other revenues 0.2 0.3 0.3 Operation and maintenance expense 164.1 122.9 118.1 Interest expense 26.8 62.0 37.9 Interest income 4.8 0.5 0.5 Balance Sheet (in millions) December 31, 2015 December 31, 2014 Predecessor Accounts receivable $ 149.4 $ 153.8 Current portion of long-term debt — 115.9 Short-term borrowings 42.1 247.3 Accounts payable 86.3 49.9 Long-term debt 630.9 1,472.8 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 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. Interest Expense and Income . The Partnership and Predecessor were charged interest for long-term debt of $35.1 million , $61.6 million and $40.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, offset by associated AFUDC of $9.2 million , $2.7 million and $6.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the 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 and the Predecessor 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 NiSource and the subsidiary. Subsequent to the Separation, cash accounts maintained by subsidiaries of Columbia OpCo were 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 was determined by the net position of each subsidiary in the money pool. The money pool weighted-average interest rate at December 31, 2015 and 2014 was 1.21% and 0.70% , respectively. The interest expense for short-term borrowings charged for the years ended December 31, 2015 , 2014 and 2013 was $0.9 million , $3.1 million and $4.1 million , respectively. Accounts Receivable . The Partnership includes in accounts receivable amounts due from the money pool discussed above of $140.5 million at December 31, 2015 for subsidiaries of Columbia OpCo in a net deposit position. The Predecessor includes in accounts receivable amounts due from the money pool discussed above of $ 125.0 million at December 31, 2014 for subsidiaries in a net deposit position. Also included in the balance at December 31, 2015 and December 31, 2014 are amounts due from subsidiaries of CPG, subsequent to the Separation, or NiSource, prior to the Separation, of $8.9 million and $28.8 million , respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Statements of Consolidated and Combined Statements of Cash Flows. All other affiliated receivables are included as Operating Activities. Short-term Borrowings . 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 is now with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. The CPG revolving credit agreement became effective at the completion of the Separation with a termination date of July 2, 2020. Each of CEG, OpCo GP and Columbia OpCo is a guarantor of CPG's revolving credit facility. As a guarantor and restricted subsidiary, Columbia OpCo is subject to various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance to their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo's partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo's business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At December 31, 2015 , neither CPG nor its subsidiaries had any restricted assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to the Partnership. CPG’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million . If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against Columbia OpCo as a guarantor. The balance of Short-term Borrowings at December 31, 2015 and December 31, 2014 of $42.1 million and $247.3 million , respectively, includes those subsidiaries of Columbia OpCo and includes those subsidiaries of the Predecessor in a net borrower position of the money pool discussed above. Net cash flows related to Short-term Borrowings are included as Financing Activities on the Statements of Consolidated and Combined Statements of Cash Flows. Accounts Payable . The affiliated accounts payable balance primarily includes amounts due for services received from CPGSC, subsequent to the Separation, and NiSource Corporate Services, prior to the Separation, and interest payable to CPG, subsequent to the Separation, and NiSource Finance, prior to the Separation. 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. Details of the long-term debt balance are summarized in the table below: Origination Date Interest Rate Maturity Date December 31, 2015 December 31, 2014 (in millions) Predecessor November 28, 2005 (1) 5.41 % November 30, 2015 $ — $ 115.9 November 28, 2005 5.45 % November 28, 2016 — 45.3 November 28, 2005 5.92 % November 28, 2025 — 133.5 November 28, 2012 4.63 % November 28, 2032 — 45.0 November 28, 2012 4.94 % November 30, 2037 — 95.0 December 19, 2012 5.16 % December 21, 2037 — 55.0 November 28, 2012 5.26 % November 28, 2042 — 170.0 December 19, 2012 5.49 % December 18, 2042 — 95.0 December 9, 2013 (2) 4.70 % December 31, 2020 630.9 834.0 Total long-term debt, including current portion $ 630.9 $ 1,588.7 (1) The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in "Current portion of long-term debt-affiliated" on the Combined Balance Sheet as of December 31, 2014. (2) 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 December 31, 2015 . Dividends . During the year ended December 31, 2015 , Columbia OpCo distributed $687.3 million to CEG, of which $500.0 million was a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. The Predecessor paid no dividends to CEG in the year ended December 31, 2014 and paid $113.0 million to CEG in the year ended December 31, 2013 . There were no restrictions on the payment by the Partnership of dividends to CEG.

Short-Term Borrowings

Short-Term Borrowings	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
Short-Term Borrowings	Short-Term Borrowings On December 5, 2014, the Partnership entered into a $500.0 million senior revolving credit facility, of which $50.0 million in letters is available. The revolving credit facility became effective at the closing of the IPO with a termination date of February 11, 2020. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls to Columbia OpCo. Obligations under the revolving credit facility are unsecured. The loans thereunder bear interest at the Partnership's option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent , (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (“LIBOR”), plus 1.000 percent , each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. The revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of CPG. The revolving indebtedness under the credit facility ranks equally with all of the Partnership's outstanding unsecured and unsubordinated debt. CPG, CEG, OpCo GP and Columbia OpCo each fully guarantee the credit facility. The revolving credit facility contains various covenants and restrictive provisions which, among other things, limit the Partnership's and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit the Partnership or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither the Partnership nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational agreements. In particular, in accordance with the partnership agreement, the general partner has adopted a policy that the Partnership will make quarterly cash distributions in amounts equal to at least the minimum quarterly distribution of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. At December 31, 2015 , neither the Partnership nor its consolidated subsidiaries had any restricted assets. If the Partnership fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $50.0 million . The revolving credit facility also contains certain financial covenants that require the Partnership to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00 . A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against the Partnership or any guarantor. As of December 31, 2015 , the Partnership had $15.0 million of outstanding borrowings and issued no letters of credit under this revolving credit facility. Short-term borrowings were as follows: At December 31, (in millions) 2015 2014 Credit facility borrowings, weighted average interest rate of 1.28% at December 31, 2015 $ 15.0 $ — Given their maturity and turnover is less than 90 days, cash flows related to the borrowings and repayments of the revolving credit facility are presented net in the Statements of Consolidated and Combined Cash Flows.

Gain on Sale of Assets

Gain on Sale of Assets	12 Months Ended
	Dec. 31, 2015
Gain On Sale of Assets [Abstract]
Gain on Sale of Assets	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 years ended December 31, 2015 , 2014 and 2013 , gains on conveyances amounted to $52.3 million , $34.5 million and $7.3 million , respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $35.8 million received by CEVCO from CNX Gas Company LLC during the year ended December 31, 2015 , for the lease of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. As of December 31, 2015 and 2014 , deferred gains of approximately $8.1 million and $19.6 million , respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated and Combined Balance Sheets. In 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million .

Property, Plant And Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant And Equipment	Property, Plant and Equipment The Partnership’s property, plant and equipment on the Consolidated and Combined Balance Sheets are classified as follows: At December 31, (in millions) 2015 2014 Predecessor Property, plant and equipment Pipeline and other transmission assets $ 6,120.0 $ 5,328.2 Storage facilities 1,370.1 1,326.5 Gas stored base gas 299.5 299.5 Gathering and processing facilities 370.2 263.3 Construction work in process 463.5 454.2 General plant, software, and other assets 307.6 259.9 Property, plant and equipment 8,930.9 7,931.6 Accumulated Depreciation and Amortization (2,960.1 ) (2,971.4 ) Net Property, plant and equipment $ 5,970.8 $ 4,960.2 The table below lists the Partnership's applicable annual depreciation rates: Year Ended December 31, 2015 2014 2013 Predecessor Predecessor Depreciation rates Pipeline and other transmission assets 1.00% - 1.73% 1.00% - 2.55% 1.50 % - 2.55% Storage facilities 2.19% - 3.00% 2.19% - 3.30% 2.19% - 3.50% Gathering and processing facilities 1.67% - 2.50% 1.67% - 2.50% 1.67 % - 2.50% General plant, software, and other assets 1.00% - 10.00% 1.00% - 10.00% 1.00% - 10.00%

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	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 December 31, 2015 and December 31, 2014 were $1,975.5 million . The Predecessor completed a quantitative ("step 1") fair value measurement of the reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded its carrying value, indicating that no impairment existed. In estimating the fair value of Columbia Gas Transmission Operations for the May 1, 2012 test, the Partnership used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Partnership utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated with the assistance of a third-party valuation firm, using multiples and assumptions inherent in today’s market. The degree of judgment involved and reliability of inputs into each model were considered in weighting the various approaches. The resulting estimate of fair value of the reporting unit, using the weighted average of the income and market approaches, exceeded its carrying value, indicating that no impairment exists under step 1 of the annual impairment test. Certain key assumptions used in determining the fair value of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Partnership used the discount rate of 5.60% for Columbia Gas Transmission Operations, resulting in excess fair value of approximately $1,643.0 million . GAAP allows entities testing goodwill for impairment the option of performing a qualitative ("step 0") assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that, based on that assessment, it is more likely than not that its fair value is less than its carrying amount. The Partnership applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2015. For the current year test, the 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 results of this assessment indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value. 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. The Partnership reviewed the market capitalization method due to the recent decline in the Partnership's unit price. Following this review, the Partnership determined there were no indicators that would require goodwill impairment testing subsequent to May 1, 2015.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Changes in the Partnership’s liability for asset retirement obligations for the years 2015 and 2014 are presented in the table below: (in millions) 2015 2014 Predecessor Balance as of January 1, $ 23.2 $ 26.3 Noncontributed net parent investment adjustments (1) (0.4 ) — Accretion expense 1.2 1.5 Additions 4.1 2.2 Settlements — (6.6 ) Change in estimated cash flows (2.8 ) (0.2 ) Balance as of December 31, $ 25.3 $ 23.2 (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.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Matters	Regulatory Matters Regulatory Assets and Liabilities Current and noncurrent regulatory assets and liabilities were comprised of the following items: At December 31, (in millions) 2015 2014 Predecessor Assets Unrecognized pension benefit and other postretirement benefit costs $ 127.1 $ 120.9 Other postretirement costs 8.9 10.8 Deferred taxes on AFUDC equity — 21.8 Other 3.1 4.5 Total Regulatory Assets $ 139.1 $ 158.0 At December 31, (in millions) 2015 2014 Predecessor Liabilities Cost of removal $ 153.5 $ 156.2 Regulatory effects of accounting for income taxes — 10.9 Unrecognized pension benefit and other postretirement benefit costs 0.6 8.3 Other postretirement costs 155.6 117.3 Other 1.2 2.9 Total Regulatory Liabilities $ 310.9 $ 295.6 No regulatory assets are earning a return on investment at December 31, 2015 . Regulatory assets of $7.2 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 7 years. Assets: Unrecognized pension benefit and other postretirement benefit costs – In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders to be recovered through base rates. Other postretirement costs – Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms. Deferred taxes on AFUDC equity - ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. The Partnership is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized. The regulatory asset was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level. Liabilities: Cost of removal - Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of some rate-regulated subsidiaries for future costs to be incurred. Regulatory effects of accounting for income taxes - Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates, which is being amortized to earnings in association with depreciation on related property. The regulatory liability was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level. Unrecognized pension benefit and other postretirement benefit costs - In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the benefits as a regulatory liability in accordance with regulatory orders. Other postretirement costs - Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the Partnership’s results, which exceeds the amount funded in the plan. Regulatory Matters Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved the Settlement. In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter. The Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25.0 million in revenues annually thereafter. The Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a 14.0% revenue requirement with a portion designated as a recovery of taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100.0 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15.0% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term. On January 28, 2016, Columbia Gas Transmission received FERC approval of its December 2015 filing to recover costs associated with the third year of its comprehensive system modernization program. Total program adjusted spend to date is $937.1 million . The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016. Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf ’s existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf intends to file a cost and revenue study with FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. The outcome of this proceeding to Columbia Gulf is not currently determinable. Cost Recovery Trackers and other similar mechanisms. Under section 4 of the NGA, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015. Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel. The recoveries and costs are both reflected in operating expenses.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities And Equity Investments [Abstract]
Variable Interest Entities And Equity Method Investments	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 Partnership's Consolidated and Combined Balance Sheets and the Partnership's portion of the results are reflected in "Equity Earnings in Unconsolidated Affiliates" on the Partnership's Statements of Consolidated and Combined Operations. In the normal course of business, the Partnership engages in various transactions with these unconsolidated affiliates. During the year ended December 31, 2015 , the Partnership had billed approximately $13.1 million for services and other costs to Millennium Pipeline. Contributions are made to these equity investees to fund the Partnership's share of projects. The following is a list of the Partnership's equity method investments at December 31, 2015 : Investee Type of Investment % of Voting Power or Interest Held Hardy Storage Company, LLC LLC Membership 49.0 % Pennant Midstream, LLC LLC Membership 47.5 % Millennium Pipeline Company, L.L.C. LLC Membership 47.5 % As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in aggregate, material to the Partnership's business, the following table contains condensed summary financial data. Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Millennium Pipeline Statement of Income Data: Net Revenues $ 206.3 $ 190.5 $ 157.8 Operating Income 136.1 128.8 101.3 Net Income 98.0 89.6 63.0 Balance Sheet Data: Current Assets 35.7 32.1 38.3 Noncurrent Assets 987.1 1,016.3 1,033.8 Current Liabilities 44.4 42.6 58.8 Noncurrent Liabilities 535.8 568.3 599.7 Total Members’ Equity 442.6 437.5 413.6 Contribution/Distribution Data: (1) Contributions to Millennium Pipeline 1.4 2.6 16.6 Distribution of earnings from Millennium Pipeline 47.5 35.6 29.0 Hardy Storage Statement of Operations Data: Net Revenues $ 23.4 $ 23.6 $ 24.4 Operating Income 15.3 16.1 16.5 Net Income 10.3 10.6 10.6 Balance Sheet Data: Current Assets 12.1 12.0 12.5 Noncurrent Assets 155.5 157.4 160.2 Current Liabilities 19.3 17.1 18.3 Noncurrent Liabilities 68.5 77.4 85.7 Total Members’ Equity 79.8 74.9 68.7 Contribution/Distribution Data: (1) Contributions to Hardy Storage — — — Distribution of earnings from Hardy Storage 2.6 2.2 3.1 Pennant Statement of Operations Data: Net Revenues $ 34.6 $ 8.5 $ 2.0 Operating Income (Loss) 17.8 (2.4 ) 1.3 Net Income (Loss) 17.8 (2.4 ) 1.3 Balance Sheet Data: Current Assets 11.0 23.7 34.1 Noncurrent Assets 389.6 380.0 231.9 Current Liabilities 8.4 8.6 11.4 Total Members’ Equity 392.2 395.1 254.6 Contribution/Distribution Data: (1) Contributions to Pennant — 66.6 108.9 Distribution of earnings from Pennant 7.1 — — Return of capital from Pennant 16.0 — — (1) Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of income tax expense were as follows: Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Income Taxes Current Federal $ 12.0 $ 21.3 $ (16.1 ) State 1.2 5.8 (11.4 ) Total Current 13.2 27.1 (27.5 ) Deferred Federal 8.8 117.7 155.9 State 1.9 21.7 24.1 Total Deferred 10.7 139.4 180.0 Deferred Investment Credits — (0.1 ) (0.1 ) Total Income Taxes $ 23.9 $ 166.4 $ 152.4 Total income taxes were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows: Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Book income before income taxes $ 554.1 $ 435.5 $ 419.3 Tax expense at statutory federal income tax rate 193.9 35.0 % 152.4 35.0 % 146.8 35.0 % Increases (reductions) in taxes resulting from: State income taxes, net of federal income tax benefit 2.0 0.4 17.9 4.1 8.2 1.9 Income not subject to income tax at the partnership level (170.6 ) (30.9 ) — — — — AFUDC-Equity (0.3 ) — (3.8 ) (0.9 ) (2.4 ) (0.6 ) Other, net (1.1 ) (0.2 ) (0.1 ) — (0.2 ) — Total Income Taxes $ 23.9 4.3 % $ 166.4 38.2 % $ 152.4 36.3 % The effective income tax rates were 4.3% , 38.2% , and 36.3% in 2015 , 2014 and 2013 , respectively. The effective tax rate for 2015 differs from the federal tax rate of 35% primarily due to the income received following the Partnership's IPO that is not subject to income tax at the partnership level. The effective tax rate is impacted by the Partnership’s IPO which modified the ownership structure and now reflects Partnership earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes. The effective tax rate for 2014 and 2013 differs from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, as well as other permanent book-to-tax differences. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items. The Partnership had no unrecognized tax benefits related to uncertain tax positions as of December 31, 2015. As of December 31, 2014 and 2013, the Predecessor financial statements included unrecognized tax benefits of zero and $0.1 million , respectively. Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of the Partnership’s net deferred tax liability were as follows: At December 31, (in millions) 2015 2014 Predecessor Deferred tax liabilities Accelerated depreciation and other property differences $ 1.0 $ 1,235.3 Pension and other postretirement/postemployment benefits — 24.3 Other regulatory assets — 62.8 Other, net — 77.9 Total Deferred Tax Liabilities 1.0 1,400.3 Deferred tax assets Deferred investment tax credits and other regulatory liabilities — (116.7 ) Net operating loss carryforward and AMT credit carryforward — (67.8 ) Other accrued liabilities — (1.4 ) Total Deferred Tax Assets — (185.9 ) Net Deferred Tax Liabilities less Deferred Tax Assets 1.0 1,214.4 Less: Deferred income taxes related to current assets and liabilities — (24.6 ) Non-Current Deferred Tax Liabilities $ 1.0 $ 1,239.0

Pension And Other Postretiremen

Pension And Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2015
Pension and Other Postretirement Benefit Expense [Abstract]
Pension and Other Postretirement Benefits Disclosure	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 contributions plans and noncontributory defined benefit 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 grantor trusts. As of July 1, 2015, in connection with the Separation, accrued pension and postretirement benefit obligations for subsidiaries of Columbia OpCo participants and related plan assets were transferred from NiSource to CPG. 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 grantor 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. Pension and Other Postretirement Benefit Plans’ Asset Management . CPG employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds may be used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. To establish a long-term rate of return for plan assets assumption, past historical capital market returns and a proprietary forecast are evaluated. The long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness. The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for the CPG plan assets represents a long-term view and are listed in the following table. In 2012, an asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, real estate, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by the projected benefit obligations of the qualified pension plans divided by the market value of qualified pension plan assets). The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on December 31, 2015 are as follows: Asset Mix Policy of Funds: Defined Benefit Pension Plan Postretirement Benefit Plan Asset Category Minimum Maximum Minimum Maximum Domestic Equities 25% 45% 35% 55% International Equities 15% 25% 15% 25% Fixed Income 23% 37% 20% 50% Real Estate/Private Equity/Hedge Funds 0% 15% 0% 0% Short-Term Investments 0% 10% 0% 10% Pension Plan and Postretirement Plan Asset Mix at December 31, 2015 and December 31, 2014 : December 31, 2015 Defined Benefit Postretirement Asset Class Asset Value % of Total Assets Asset Value % of Total Assets (in millions) (in millions) Domestic Equities $ 115.9 39.4 % $ 95.3 44.6 % International Equities 51.4 17.5 % 40.1 18.7 % Fixed Income 101.5 34.4 % 71.8 33.6 % Cash/Other 25.5 8.7 % 6.7 3.1 % Total $ 294.3 100.0 % $ 213.9 100.0 % December 31, 2014 Defined Benefit Postretirement Asset Class Asset Value % of Total Assets Asset Value % of Total Assets (in millions) (in millions) Domestic Equities $ 125.2 41.1 % $ 99.9 47.2 % International Equities 55.0 18.1 % 38.9 18.4 % Fixed Income 105.0 34.4 % 72.2 34.1 % Real Estate/Private Equity/Hedge Funds 15.4 5.0 % — — % Cash/Other 4.2 1.4 % 0.6 0.3 % Total $ 304.8 100.0 % $ 211.6 100.0 % The categorization of investments into the asset classes in the table above are based on definitions established by the CPG Benefits Committee. Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the CPG Pension Plan Trust and OPEB investment assets at fair value as of December 31, 2015 and 2014 . Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total CPG Pension Plan Trust and OPEB investment assets at fair value classified within Level 3 were zero and $15.3 million as of December 31, 2015 and December 31, 2014 , respectively. Such amounts were approximately zero and 3% of the CPG Pension Plan Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2015 and 2014 , respectively. Valuation Techniques Used to Determine Fair Value: Level 1 Measurements Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values. Level 2 Measurements Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing. Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are classified as Level 2. The funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments. Level 3 Measurements Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds' underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods. The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days' notice. Private equity investment strategies include buy-out, venture capital, growth equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships. Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership's fair value as recorded in the partnerships' audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds' underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation. For the year ended December 31, 2015 , there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets. The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts: Fair Value Measurements (in millions) December 31, Quoted Prices in Active Significant Other Significant Pension plan assets Cash $ 0.8 $ 0.8 $ — $ — Equity securities International equities 5.4 5.4 — — Fixed income securities Government 7.1 — 7.1 — Corporate 10.8 — 10.8 — Commingled funds Short-term money markets 25.5 — 25.5 — U.S. equities 115.9 — 115.9 — International equities 45.7 — 45.7 — Fixed income 83.1 — 83.1 — Pension plan assets subtotal 294.3 6.2 288.1 — Other postretirement benefit plan assets Commingled funds Short-term money markets 6.8 — 6.8 — U.S. equities 13.0 — 13.0 — Mutual funds U.S. equities 82.3 82.3 — — International equities 40.1 40.1 — — Fixed income 71.7 71.7 — — Other postretirement benefit plan assets subtotal 213.9 194.1 19.8 — Due to brokers, net (1) (0.3 ) Accrued investment income/dividends 0.5 Total pension and other postretirement benefit plan assets $ 508.4 $ 200.3 $ 307.9 $ — (1) This class represents pending trades with brokers. The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2015 : (in millions) Balance at January 1, 2015 Total gains or losses (unrealized / realized) Purchases (Sales) Transfers into/(out of) level 3 Separation Allocation (1) Balance at December 31, 2015 Fixed income securities Other fixed income $ 0.1 $ — $ — $ — $ — $ (0.1 ) $ — Private equity limited partnerships U.S. multi-strategy 7.3 — — — — (7.3 ) — International multi-strategy 4.6 — — — — (4.6 ) — Distressed opportunities 1.0 — — — — (1.0 ) — Real estate 2.3 — — — — (2.3 ) — Total $ 15.3 $ — $ — $ — $ — $ (15.3 ) $ — (1) Level 3 assets were not contributed to the Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation. The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts: Fair Value Measurements (in millions) December 31, Quoted Prices in Active Significant Other Significant Pension plan assets Cash $ 2.2 $ 2.2 $ — $ — Equity securities International equities 17.6 17.5 0.1 — Fixed income securities Government 15.5 13.7 1.8 — Corporate 33.6 — 33.6 — Mortgages/Asset backed securities 0.4 — 0.4 — Other fixed income 0.1 — — 0.1 Commingled funds Short-term money markets 4.3 — 4.3 — U.S. equities 125.2 — 125.2 — International equities 36.6 — 36.6 — Fixed income 53.5 — 53.5 — Private equity limited partnerships U.S. multi-strategy (1) 7.3 — — 7.3 International multi-strategy (2) 4.6 — — 4.6 Distressed opportunities 1.0 — — 1.0 Real Estate 2.3 — — 2.3 Pension plan assets subtotal 304.2 33.4 255.5 15.3 Other postretirement benefit plan assets Commingled funds Short-term money markets 0.7 — 0.7 — U.S. equities 13.6 — 13.6 — Mutual funds U.S. equities 86.4 86.4 — — International equities 38.9 38.9 — — Fixed income 72.0 72.0 — — Other postretirement benefit plan assets subtotal 211.6 197.3 14.3 — Due to brokers, net (3) (0.1 ) Accrued investment income/dividends 0.1 Net receivables 0.6 Total pension and other postretirement benefit plan assets $ 516.4 $ 230.7 $ 269.8 $ 15.3 (1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily in the United States. (2) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States. (3) This class represents pending trades with brokers. The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2014 : (in millions) Balance at January 1, 2014 Total gains or losses (unrealized / realized) Purchases (Sales) Transfers into/(out of) level 3 Balance at December 31, 2014 Fixed income securities Other fixed income $ — $ — $ 0.1 $ — $ — $ 0.1 Private equity limited partnerships U.S. multi-strategy 7.6 0.3 0.3 (0.9 ) — 7.3 International multi-strategy 5.0 (0.1 ) 0.1 (0.4 ) — 4.6 Distress opportunities 1.2 — — (0.2 ) — 1.0 Real estate 2.6 0.3 — (0.6 ) — 2.3 Total $ 16.4 $ 0.5 $ 0.5 $ (2.1 ) $ — $ 15.3 As noted above, the Partnership follows multiple employer accounting under the provisions of GAAP and therefore, is allocated a ratable portion of the CPG’s grantor trusts for the plans in which its employees and retirees participate. The allocation of the fair value of assets is based upon the ratable share of plan funding and participant benefit payments. Investment activity within the trust occurs at the trust level, and the Partnership is allocated a portion of investment gains and losses based on its percentage of the total CPG projected benefit obligation. CPG Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure . The following table provides a reconciliation of the plans’ funded status and amounts reflected in the Partnership’s Consolidated and Combined Balance Sheets at December 31 based on a December 31 measurement date: Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2015 2014 Predecessor Predecessor Change in projected benefit obligation (1) Benefit obligation at beginning of year $ 345.2 $ 327.1 $ 108.9 $ 105.5 Service cost 5.3 4.8 1.0 1.1 Interest cost 12.5 13.7 4.0 4.6 Plan participants’ contributions — — 1.6 1.9 Actuarial loss (gain) (7.3 ) 20.0 (11.6 ) 4.6 Benefits paid (23.5 ) (20.4 ) (7.5 ) (9.1 ) Estimated benefits paid by incurred subsidy — — 0.2 0.3 Contributed/noncontributed projected benefit obligation (2) (4.6 ) — (3.2 ) — Projected benefit obligation at end of year $ 327.6 $ 345.2 $ 93.4 $ 108.9 Change in plan assets Fair value of plan assets at beginning of year $ 304.7 $ 299.1 $ 211.6 $ 198.8 Actual return on plan assets 0.6 19.3 (2.0 ) 9.2 Employer contributions 16.5 6.7 11.3 10.8 Plan participants’ contributions — — 1.6 1.9 Benefits paid (23.5 ) (20.4 ) (7.5 ) (9.1 ) Contributed/noncontributed plan assets (2) (4.0 ) — (1.1 ) — Fair value of plan assets at end of year $ 294.3 $ 304.7 $ 213.9 $ 211.6 Funded status at end of year $ (33.3 ) $ (40.5 ) $ 120.5 $ 102.7 Amounts recognized in the statement of financial position consist of: Noncurrent assets $ — $ — $ 120.5 $ 109.8 Current liabilities (0.1 ) — — — Noncurrent liabilities (33.2 ) (40.5 ) — (7.1 ) Net amount recognized at end of year (3) $ (33.3 ) $ (40.5 ) $ 120.5 $ 102.7 Amounts recognized as regulatory assets/liabilities (4) Unrecognized prior service (credit) cost $ (3.0 ) $ (4.0 ) $ 0.1 $ 0.1 Unrecognized actuarial loss (gain) 130.3 124.5 (0.4 ) (8.3 ) Total recognized regulatory assets (liabilities) $ 127.3 $ 120.5 $ (0.3 ) $ (8.2 ) (1) The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation. (2) Reflects the removal of amounts related to Crossroads Pipeline Company and CPGSC, which 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) The Partnership recognizes in its Consolidated and Combined Balance Sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. (4) The Partnership determined that the future recovery of pension and other postretirement benefits costs is probable. The Partnership recorded regulatory assets and liabilities of $127.1 million and $0.6 million , respectively, as of December 31, 2015 , and $120.9 million and $8.3 million , respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss. The Partnership’s accumulated benefit obligation for its pension plans was $327.6 million and $345.2 million as of December 31, 2015 and 2014 , respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The Partnership's pension plans were underfunded by $33.3 million at December 31, 2015 , compared to being underfunded by $40.5 million by December 31, 2014 . The improvement in the funded status was due primarily to an increase in the discount rate from the prior measurement date and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed $16.5 million and $6.7 million to its pension plans in 2015 and 2014 , respectively. The Partnership’s funded status for its other postretirement benefit plans improved by $17.8 million to an overfunded status of $120.5 million primarily due to favorable claims experience and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed approximately $11.3 million and $10.8 million to its other postretirement benefit plans in 2015 and 2014 , respectively. No amounts of the Partnership’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG or any of its subsidiaries in 2016 . In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plans' 2013 service cost plus interest cost and, therefore, settlement accounting was required. As a result, the Predecessor recorded a settlement charge of $12.4 million in 2013. The Predecessor's net periodic pension benefit cost for 2013 was decreased by $1.2 million as a result of the interim remeasurements. The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for the Partnership’s various plans as of December 31: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 Predecessor Predecessor Weighted-average assumptions to determine benefit obligation Discount Rate 4.05 % 3.64 % 4.28 % 3.95 % Rate of Compensation Increases 4.00 % 4.00 % Health Care Trend Rates Trend for Next Year 8.38 % 6.90 % Ultimate Trend 4.50 % 4.50 % Year Ultimate Trend Reached 2022 2021 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: (in millions) 1% point increase 1% point decrease Effect on service and interest components of net periodic cost $ 0.1 $ (0.1 ) Effect on accumulated postretirement benefit obligation 2.5 (2.3 ) The Partnership expects to make contributions of approximately $0.1 million to its pension plans and approximately $0.9 million to its postretirement medical and life plans in 2016 . The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure the Partnership's benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees: (in millions) Pension Benefits Other Federal Year(s) 2016 $ 27.2 $ 6.2 $ 0.3 2017 27.1 6.2 0.3 2018 27.9 6.3 0.3 2019 28.0 6.4 0.3 2020 30.0 6.4 0.3 2021-2025 145.8 31.4 1.2 The following table provides the components of the plans’ net periodic benefits cost for the years ended December 31, 2015 , 2014 and 2013 : Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2013 2015 2014 2013 Predecessor Predecessor Predecessor Predecessor Components of Net Periodic Benefit Cost (Income) Service cost $ 5.3 $ 4.8 $ 4.8 $ 1.0 $ 1.1 $ 1.5 Interest cost 12.5 13.7 12.6 4.0 4.6 4.9 Expected return on assets (23.6 ) (23.8 ) (22.0 ) (17.4 ) (16.5 ) (13.5 ) Amortization of prior service (credit) cost (0.9 ) (1.0 ) (0.9 ) 0.1 0.1 0.1 Recognized actuarial loss (gain) 8.2 6.6 10.6 (0.2 ) (0.1 ) 1.0 Net Periodic Benefit Cost (Income) 1.5 0.3 5.1 (12.5 ) (10.8 ) (6.0 ) Settlement loss — — 12.4 — — — Total Net Periodic Benefit Cost (Income) $ 1.5 $ 0.3 $ 17.5 $ (12.5 ) $ (10.8 ) $ (6.0 ) The $1.2 million increase in the actuarially-determined pension benefit cost is due primarily to decreased discount rates and unfavorable asset returns in 2015 compared to 2014 . For its other postretirement benefit plans, the Partnership recognized $12.5 million in net periodic benefit income in 2015 compared to net periodic benefit income of $10.8 million in 2014 due primarily to favorable claims experience, offset by a decrease in discount rates in 2015 compared to 2014 . The following table provides the key assumptions that were used to calculate the net periodic benefits cost for the Partnership’s various plans: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Predecessor Predecessor Predecessor Predecessor Weighted-average assumptions to determine net periodic benefit cost Discount Rate 3.84 % 4.34 % 3.36 % 4.09 % 4.74 % 3.92 % Expected Long-Term Rate of Return on Plan Assets 8.20 % 8.30 % 8.30 % 8.06 % 8.14 % 8.15 % Rate of Compensation Increases 4.00 % 4.00 % 4.00 % The Partnership believes it is appropriate to assume an 8.20% and 8.06% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2015 pension benefits cost. This is primarily based on asset mix and historical rates of return. The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability: Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2015 2014 Predecessor Predecessor Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities Net actuarial loss $ 14.1 $ 24.4 $ 7.8 $ 11.7 Less: amortization of prior service (credit) cost 0.9 1.0 (0.1 ) — Less: amortization of net actuarial (gain) loss (8.2 ) (6.6 ) 0.2 — Total recognized in regulatory assets/liabilities $ 6.8 $ 18.8 $ 7.9 $ 11.7 Amount recognized in net periodic benefit cost and regulatory assets/liabilities $ 8.3 $ 19.1 $ (4.6 ) $ 0.9 Based on a December 31 measurement date, the net unrecognized actuarial loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2016 for the pension plans are $10.1 million , $(0.9) million and zero , respectively, and for other postretirement benefit plans are $0.2 million , $0.1 million and zero , respectively.

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value	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. As of December 31, 2015 , the fair value approximates carrying value as these securities bear interest at variable rates. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2015 and 2014 , there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments. The carrying amount and estimated fair values of financial instruments were as follows: At December 31, (in millions) Carrying Amount 2015 Estimated Fair Value 2015 Carrying Amount 2014 Estimated Fair Value 2014 Predecessor Current portion of long-term debt-affiliated $ — $ — $ 115.9 $ 120.0 Long-term debt-affiliated 630.9 630.9 1,472.8 1,550.4

Other Commitments And Contingen

Other Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Other Commitments And Contingencies	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 December 31, 2015 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 Letters of credit 18.1 18.1 — — — — — Total commercial commitments $ 2,768.1 $ 18.1 $ — $ 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. First, if CPG discharges or defeases its obligations with respect to any series of CPG’s senior notes, then any guarantee will be released with respect to that series. Second, if no event of default has occurred and is continuing under the indenture, a Guarantor will be automatically and unconditionally released and discharged from its guarantee (i) at any time after June 1, 2018, upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not CPG’s affiliate, of all of CPG’s direct or indirect limited partnership, limited liability or other equity interests in the Guarantor; (ii) upon the merger of a guarantor into CPG or any other Guarantor or the liquidation and dissolution of such Guarantor; or (iii) at any time after June 1, 2018, upon release of all guarantees or other obligations of the Guarantor with respect to any of CPG’s funded debt, except CPG’s senior notes. Lines and Letters of Credit. The Partnership maintains a $500.0 million senior revolving credit facility, of which $50.0 million is available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures, and the funding of capital calls. As of December 31, 2015 , the Partnership had $15.0 million in outstanding borrowings and no letters of credit under the revolving credit facility. CPG maintains a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. CPG expects that $750.0 million of the facility will be utilized as credit support for Columbia OpCo and its subsidiaries and the remaining $750.0 million of the facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG's $1,000.0 million commercial paper program. OpCo GP and Columbia OpCo, together with CEG, have each fully guaranteed the CPG credit facility. As of December 31, 2015 , CPG had no borrowings outstanding and $18.1 million in letters of credit outstanding under its revolving credit facility. CPG has established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the "Securities Act"). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million . OpCo GP and Columbia OpCo, together with CEG, have each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the Promissory Notes. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015 , CPG had no Promissory Notes outstanding under the Program. Other 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. B. 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 Consolidated and Combined Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated and Combined Balance Sheets. Air The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. The actions listed below could require further reductions in emissions from various emission sources. 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 CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing 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. The EPA has already promulgated regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the U.S. on an annual basis. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane. New Source Performance Standards : On August 18, 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. Semiannual leak detection and repair requirements using optical gas imaging are proposed for all components at new or existing compressor stations. Existing compressor stations trigger leak detection and repair requirements if any unit at the facility is modified. The EPA proposed additional requirements for any new or modified centrifugal or reciprocating compressors. Replacement of wet seals with dry seals or demonstrating a 95% reduction of methane emissions from wet seals is proposed for centrifugal compressors and rod packing replacement for reciprocating compressors is proposed every 26,000 hours of operation or every three years. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time. C. Operating Lease Commitments. The Partnership leases assets in several areas of its operations. Payments made in connection with operating leases were $18.5 million in 2015 , $14.9 million in 2014 and $13.4 million in 2013 , and are primarily charged to operation and maintenance expense as incurred. Future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are: (in millions) Operating Leases (1) 2016 $ 4.5 2017 5.9 2018 5.5 2019 4.8 2020 4.7 After 21.2 Total future minimum payments $ 46.6 (1) Operating lease expense includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above. D. Service Obligations . The Partnership has entered into various service agreements whereby the Partnership is contractually obligated to make certain minimum payments in future periods. The Partnership has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2016 to 2025, require the Partnership to pay fixed monthly charges. The estimated aggregate amounts of minimum fixed payments at December 31, 2015 , were: (in millions) Pipeline Service Agreements 2016 $ 51.5 2017 49.5 2018 42.0 2019 25.4 2020 24.2 After 66.8 Total future minimum payments $ 259.4

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2015
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax: (in millions) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Loss (1) Balance as of January 1, 2013 - Predecessor $ (18.7 ) $ (0.1 ) $ (18.8 ) Other comprehensive income before reclassifications — — — Amounts reclassified from accumulated other comprehensive income 1.1 — 1.1 Net current-period other comprehensive income 1.1 — 1.1 Balance as of December 31, 2013 - Predecessor $ (17.6 ) $ (0.1 ) $ (17.7 ) Other comprehensive income before reclassifications — — — Amounts reclassified from accumulated other comprehensive income 1.0 — 1.0 Net current-period other comprehensive income 1.0 — 1.0 Balance as of December 31, 2014 - Predecessor $ (16.6 ) $ (0.1 ) $ (16.7 ) Predecessor net tax liabilities not assumed by Columbia OpCo (2) $ (10.2 ) $ (0.1 ) (10.3 ) Other comprehensive income before reclassifications — (0.3 ) (0.3 ) Amounts reclassified from accumulated other comprehensive income (3) 1.5 0.1 1.6 Net current-period other comprehensive income 1.5 (0.2 ) 1.3 Allocation of accumulated other comprehensive loss to noncontrolling interest (21.4 ) (0.3 ) (21.7 ) Balance as of December 31, 2015 $ (3.9 ) $ (0.1 ) $ (4.0 ) (1) All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits. (2) 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. (3) Includes amounts allocated to noncontrolling interest. Equity Method Investment During 2008, Millennium Pipeline, in which the Partnership has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties. During August 2010, Millennium Pipeline completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million , $375.0 million at 5.33% due June 30, 2027 and $350.0 million at 6.00% due June 30, 2032 . Upon the issuance of these notes, Millennium Pipeline repaid all outstanding borrowings under its credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were primarily accounted for as cash flow hedges by Millennium Pipeline. As an equity method investment, the Partnership is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss of $25.0 million , before tax, related to these terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $25.0 million and $16.6 million at December 31, 2015 and December 31, 2014 , respectively, is included in unrealized losses on cash flow hedges above.

Other, Net

Other, Net	12 Months Ended
	Dec. 31, 2015
Other Nonoperating Income (Expense) [Abstract]
Other, Net	Other, Net Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor AFUDC Equity $ 28.3 $ 11.0 $ 6.8 Miscellaneous (1) 3.7 (2.2 ) 10.8 Total Other, net $ 32.0 $ 8.8 $ 17.6 (1) Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

Segments Of Business

Segments Of Business	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segments Of Business	Segments of Business Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Chief Executive Officer of OpCo GP is the chief operating decision maker for the periods presented. At December 31, 2015 , the Partnership’s operations comprise one operating segment. The Partnership's segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services and development of mineral rights positions. The chief operating decision maker evaluates the performance of the Partnership operations and determines how to allocate resources on a consolidated basis.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following tables provide additional information regarding the Partnership’s Statements of Consolidated and Combined Cash Flows for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Supplemental Disclosures of Cash Flow Information Non-cash transactions: Capital expenditures included in current liabilities (1) $ 122.7 $ 78.5 $ 53.1 Schedule of interest and income taxes paid: Cash paid for interest, net of interest capitalized amounts $ 40.3 $ 53.6 $ 39.5 Cash paid for income taxes 0.2 21.5 10.2 (1) Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated and Combined Balance Sheets.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Concentration of Credit Risk	Concentration of Credit Risk Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for greater than 10% of total operating revenues in the years ended December 31, 2015 , 2014 and 2013 . The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in millions) Total Operating Revenues Percentage of Total Operating Revenues Total Operating Revenues Percentage of Total Operating Revenues Total Operating Revenues Percentage of Total Operating Revenues Predecessor Predecessor Columbia Gas of Ohio (1) $ 167.3 12.6 % $ 168.5 12.5 % $ 167.5 14.2 % (1) Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release arrangements with third parties which ultimately can decrease the net revenue amount we receive from Columbia Gas of Ohio in any given period. The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of the Partnership.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Quarterly Financial Data	Quarterly Financial Data (Unaudited) (in millions, except per unit data) First Quarter Second Quarter Third Quarter Fourth Quarter 2015 Operating Revenues $ 339.2 $ 315.6 $ 320.0 $ 357.0 Operating Income 162.0 109.2 142.8 136.3 Net Income 131.2 107.8 144.6 146.6 Predecessor net income prior to IPO on February 11, 2015 42.7 — — — Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO 75.2 91.5 122.6 124.2 Net income attributable to limited partners subsequent to IPO 13.3 16.3 22.0 22.4 Net Income Per Limited Partner Unit (basic and diluted) Common Units 0.13 0.17 0.22 0.22 Subordinated Units 0.13 0.16 0.22 0.22 2014 Operating Revenues $ 345.5 $ 343.4 $ 317.6 $ 340.4 Operating Income 158.5 103.2 93.8 133.2 Net Income 92.5 59.0 53.2 64.4

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Event	Subsequent Events Partnership Distribution. On January 29, 2016 , the board of directors of MLP GP, the Partnership's general partner, declared a quarterly cash distribution for the period October 1, 2015 , through December 31, 2015 , of $0.1800 per unit, or $18.1 million in total. This distribution is payable on February 19, 2016 , to unitholders of record as of February 11, 2016 . Columbia OpCo Distribution. On February 16, 2016 , Columbia OpCo distributed $129.2 million of earnings to limited partners. The Partnership received a distribution of $20.3 million and CEG received $108.9 million based on the respective ownership percentages in Columbia OpCo.

Nature Of Operations And Summ34

Nature Of Operations And Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Company Structure And Principles Of Consolidation	Company Structure and Basis of Presentation . Columbia Pipeline Partners LP (the "Partnership") was formed in Delaware on December 5, 2007, as a subsidiary of NiSource Inc. ("NiSource"). 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. 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 that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under 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. As a result of this control and the 15.7% limited partner interest, the Partnership 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 annual 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 annual report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows: • The Consolidated and Combined Balance Sheets consist of the consolidated balance sheet of the Partnership as of December 31, 2015 and the combined balance sheet of the Predecessor as of December 31, 2014 . • The Statements of Consolidated and Combined Operations consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Comprehensive Income consist of the consolidated results of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Cash Flows consist of the consolidated cash flows of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined cash flows of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . • The Statements of Consolidated and Combined Equity and Partners' Capital consist of the consolidated activity of the Partnership for the period from February 11, 2015 through December 31, 2015 and the combined activity of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the years ended December 31, 2014 and 2013 . The Partnership’s accompanying Consolidated and Combined Financial Statements have been prepared in accordance with GAAP. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream, CEVCO, CNS Microwave, OpCo GP, Columbia OpCo and the Partnership. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline, and Pennant. All intercompany transactions and balances have been eliminated.
Use Of Estimates	Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents . Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is the Partnership's best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
Basis Of Accounting For Rate-Regulated Subsidiaries	Basis of Accounting for Rate-Regulated Subsidiaries . Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated and Combined Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. In the event that regulation significantly changes the opportunity for the Partnership to recover its costs in the future, all or a portion of the Partnership’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of the Partnership’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of regulatory accounting, the Partnership would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, the Partnership’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 12, "Regulatory Matters," in the Notes to Consolidated and Combined Financial Statements for further discussion.
Property, Plant and Equipment and Related AFUDC and Maintenance	Property, Plant and Equipment and Related AFUDC and Maintenance . Property, plant and equipment is stated at cost. The Partnership's rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. The Partnership's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties. The Partnership capitalizes AFUDC on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and ADUFC equity are summarized in the table below: 2015 2014 2013 Debt Equity Debt Equity Debt Equity Predecessor Predecessor Columbia Gas Transmission 1.8 % 6.3 % 0.9 % 3.0 % 2.5 % 3.2 % Columbia Gulf 2.9 % 6.3 % 2.1 % 9.4 % 2.5 % 3.2 % The Partnership follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.
Gas-Stored Base Gas	Gas Stored-Base Gas. Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were no purchases of base gas during the years ended December 31, 2015 , 2014 and 2013 . Please see Note 8, "Gain on Sale of Assets," in the Notes to Consolidated and Combined Financial Statements for information regarding the sale of storage base gas in 2013 . Gas stored-base gas is included in Property, plant and equipment on the Consolidated and Combined Balance Sheets.
Amortization Of Software Costs	Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. The Partnership amortized $5.8 million in 2015 , $4.3 million in 2014 and $5.0 million in 2013 related to software costs. The Partnership’s unamortized software balance was $27.1 million and $18.3 million at December 31, 2015 and 2014 , respectively.
Goodwill	Goodwill. The Partnership has $1,975.5 million in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the CEG acquisition on November 1, 2000. Please see Note 10, "Goodwill," in the Notes to Consolidated and Combined Financial Statements for further discussion.
Impairments	Impairments. An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long-lived assets is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long-lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.
Revenue Recognition	Revenue Recognition. Revenue is recorded as services are performed. Revenues are billed to customers monthly at rates established through the FERC's cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed. The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues for both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. The Partnership provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided. Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage. The Partnership includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realized. Royalty revenue was $26.5 million , $43.8 million and $21.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations. The Partnership periodically recognizes gains on the conveyance of mineral interest related to pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if the Partnership has a substantial obligation for future performance. As the obligation for future performance is satisfied, the deferred revenue is relieved and the associated gain is recognized. Gains on conveyances amounted to $52.3 million , $34.5 million and $7.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations.
Estimated Rate Refunds	Estimated Rate Refunds . The Partnership collects revenue subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.
Accounting For Exchange And Balancing Arrangements Of Natural Gas	Accounting for Exchange and Balancing Arrangements of Natural Gas. The Partnership enters into balancing and exchange arrangements of natural gas as part of its operations. The Partnership records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on the Partnership’s Consolidated and Combined Balance Sheets, as appropriate.
Income Taxes And Investment Tax Credits	Income Taxes and Investment Tax Credits. 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. The Predecessor's operating results were included in NiSource's consolidated U.S. federal and in consolidated, combined or stand-alone state income tax returns. Amounts presented in the combined financial statements prior to the IPO relate to income taxes that have been determined on a separate tax return basis, and the Predecessor's contribution to NiSource's net operating losses and tax credits have been included in the Predecessor's financial statements.
Environmental Expenditures	Environmental Expenditures. The Partnership accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The reserves for estimated environmental expenditures are recorded on the Consolidated and Combined Balance Sheets in “Other Accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. The Partnership establishes regulatory assets on the Consolidated and Combined Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 17, "Other Commitments and Contingencies" in the Notes to Consolidated and Combined Financial Statements for further discussion.
Accounting for Investments	Accounting for Investments. The Partnership accounts for its ownership interests in Millennium Pipeline using the equity method of accounting. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where the Partnership (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence. The Partnership has a 49% interest in Hardy Storage. The Predecessor had a 50% interest in Hardy Storage. The Partnership and the Predecessor reflect the investment in Hardy Storage as an equity method investment. Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. During the third quarter of 2015, an additional member, an affiliate of Williams Partners, joined the Pennant joint venture. Williams Partners' initial ownership investment in Pennant is 5.00% , and by funding specified investment amounts for future growth projects, Williams Partners can invest directly in the growth of Pennant. Such funding will potentially increase Williams Partners' ownership in Pennant up to 33.33% over a defined investment period. As a result of the buy-in, Columbia Midstream received $12.7 million in cash and recorded a gain of $2.9 million , and its ownership interest in Pennant decreased from 50.0% to 47.5% . The Partnership accounts for the joint venture under the equity method of accounting.
Natural Gas and Oil Properties	Natural Gas and Oil Properties. CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method. CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015 and 2014 : (in millions) 2015 2014 Beginning Balance $ 14.9 $ 1.9 Additions pending the determination of proved reserves 1.3 20.1 Reclassifications of proved properties (14.5 ) (7.1 ) Ending Balance $ 1.7 $ 14.9 As of December 31, 2015 , there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to one project initiated in 2013 .

Nature Of Operations And Summ35

Nature Of Operations And Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of AFUDC Debt and Equity Rates	2015 2014 2013 Debt Equity Debt Equity Debt Equity Predecessor Predecessor Columbia Gas Transmission 1.8 % 6.3 % 0.9 % 3.0 % 2.5 % 3.2 % Columbia Gulf 2.9 % 6.3 % 2.1 % 9.4 % 2.5 % 3.2 %
Capitalized Exploratory Well Costs, Roll Forward	(in millions) 2015 2014 Beginning Balance $ 14.9 $ 1.9 Additions pending the determination of proved reserves 1.3 20.1 Reclassifications of proved properties (14.5 ) (7.1 ) Ending Balance $ 1.7 $ 14.9

Initial Public Offering Initial

Initial Public Offering Initial Public Offering (Tables)	12 Months Ended
	Dec. 31, 2015
Initial Public Offering [Abstract]
Change From Net Income Attributable to the Partnership and Transfers to Noncontrolling Interest	Year Ended December 31, (in millions) 2015 Net income attributable to the Partnership $ 74.0 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 $ (350.4 )

Partners' Equity and Cash Dis37

Partners' Equity and Cash Distributions (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Distributions Made to Limited Partner, by Distribution	(in millions, except per unit amounts) Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2015 (1) May 13, 2015 May 20, 2015 $ 0.0912 $ 9.2 June 30, 2015 August 13, 2015 August 20, 2015 0.1675 16.9 September 30, 2015 November 13, 2015 November 20, 2015 0.1725 17.4 December 31, 2015 February 11, 2016 February 19, 2016 0.1800 18.1 (1) The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.

Net Income Per Limited Partne38

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Net Income Per Limited Partner Unit	Year Ended December 31, 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 $ 32.9 $ 28.7 $ — $ 61.6 Net income in excess of distribution (1) 6.7 5.1 0.6 12.4 Net income attributable to partners $ 39.6 $ 33.8 $ 0.6 $ 74.0 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 $ 0.74 $ 0.72 $ 0.74 (1) Net income attributable to partners in excess of distribution is for the period subsequent to the IPO.

Transactions With Affiliates (T

Transactions With Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Transactions With Affiliates	Statement of Operations Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Transportation revenues $ 47.1 $ 95.8 $ 94.3 Storage revenues 26.2 53.2 53.6 Other revenues 0.2 0.3 0.3 Operation and maintenance expense 164.1 122.9 118.1 Interest expense 26.8 62.0 37.9 Interest income 4.8 0.5 0.5 Balance Sheet (in millions) December 31, 2015 December 31, 2014 Predecessor Accounts receivable $ 149.4 $ 153.8 Current portion of long-term debt — 115.9 Short-term borrowings 42.1 247.3 Accounts payable 86.3 49.9 Long-term debt 630.9 1,472.8
Schedule of Related Party Transactions, Long-Term Debt	Origination Date Interest Rate Maturity Date December 31, 2015 December 31, 2014 (in millions) Predecessor November 28, 2005 (1) 5.41 % November 30, 2015 $ — $ 115.9 November 28, 2005 5.45 % November 28, 2016 — 45.3 November 28, 2005 5.92 % November 28, 2025 — 133.5 November 28, 2012 4.63 % November 28, 2032 — 45.0 November 28, 2012 4.94 % November 30, 2037 — 95.0 December 19, 2012 5.16 % December 21, 2037 — 55.0 November 28, 2012 5.26 % November 28, 2042 — 170.0 December 19, 2012 5.49 % December 18, 2042 — 95.0 December 9, 2013 (2) 4.70 % December 31, 2020 630.9 834.0 Total long-term debt, including current portion $ 630.9 $ 1,588.7 (1) The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in "Current portion of long-term debt-affiliated" on the Combined Balance Sheet as of December 31, 2014. (2) 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

Short-Term Borrowings (Tables)

Short-Term Borrowings (Tables)	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
Schedule Of Short-Term Borrowings	At December 31, (in millions) 2015 2014 Credit facility borrowings, weighted average interest rate of 1.28% at December 31, 2015 $ 15.0 $ —

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Schedule Of Property, Plant And Equipment	At December 31, (in millions) 2015 2014 Predecessor Property, plant and equipment Pipeline and other transmission assets $ 6,120.0 $ 5,328.2 Storage facilities 1,370.1 1,326.5 Gas stored base gas 299.5 299.5 Gathering and processing facilities 370.2 263.3 Construction work in process 463.5 454.2 General plant, software, and other assets 307.6 259.9 Property, plant and equipment 8,930.9 7,931.6 Accumulated Depreciation and Amortization (2,960.1 ) (2,971.4 ) Net Property, plant and equipment $ 5,970.8 $ 4,960.2
Schedule of Depreciation Rates	Year Ended December 31, 2015 2014 2013 Predecessor Predecessor Depreciation rates Pipeline and other transmission assets 1.00% - 1.73% 1.00% - 2.55% 1.50 % - 2.55% Storage facilities 2.19% - 3.00% 2.19% - 3.30% 2.19% - 3.50% Gathering and processing facilities 1.67% - 2.50% 1.67% - 2.50% 1.67 % - 2.50% General plant, software, and other assets 1.00% - 10.00% 1.00% - 10.00% 1.00% - 10.00%

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Changes In Liability For Asset Retirement Obligations	(in millions) 2015 2014 Predecessor Balance as of January 1, $ 23.2 $ 26.3 Noncontributed net parent investment adjustments (1) (0.4 ) — Accretion expense 1.2 1.5 Additions 4.1 2.2 Settlements — (6.6 ) Change in estimated cash flows (2.8 ) (0.2 ) Balance as of December 31, $ 25.3 $ 23.2 (1) Reflects the removal of amounts related to Crossroads Pipeline Company, which was included in the Predecessor, but was not contributed to the Partnership.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	At December 31, (in millions) 2015 2014 Predecessor Assets Unrecognized pension benefit and other postretirement benefit costs $ 127.1 $ 120.9 Other postretirement costs 8.9 10.8 Deferred taxes on AFUDC equity — 21.8 Other 3.1 4.5 Total Regulatory Assets $ 139.1 $ 158.0
Regulatory Liabilities	At December 31, (in millions) 2015 2014 Predecessor Liabilities Cost of removal $ 153.5 $ 156.2 Regulatory effects of accounting for income taxes — 10.9 Unrecognized pension benefit and other postretirement benefit costs 0.6 8.3 Other postretirement costs 155.6 117.3 Other 1.2 2.9 Total Regulatory Liabilities $ 310.9 $ 295.6

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities And Equity Investments [Abstract]
Equity Method Investments Schedule of Ownership Percentage	The following is a list of the Partnership's equity method investments at December 31, 2015 : Investee Type of Investment % of Voting Power or Interest Held Hardy Storage Company, LLC LLC Membership 49.0 % Pennant Midstream, LLC LLC Membership 47.5 % Millennium Pipeline Company, L.L.C. LLC Membership 47.5 %
Schedule Of Equity Method Investments	Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Millennium Pipeline Statement of Income Data: Net Revenues $ 206.3 $ 190.5 $ 157.8 Operating Income 136.1 128.8 101.3 Net Income 98.0 89.6 63.0 Balance Sheet Data: Current Assets 35.7 32.1 38.3 Noncurrent Assets 987.1 1,016.3 1,033.8 Current Liabilities 44.4 42.6 58.8 Noncurrent Liabilities 535.8 568.3 599.7 Total Members’ Equity 442.6 437.5 413.6 Contribution/Distribution Data: (1) Contributions to Millennium Pipeline 1.4 2.6 16.6 Distribution of earnings from Millennium Pipeline 47.5 35.6 29.0 Hardy Storage Statement of Operations Data: Net Revenues $ 23.4 $ 23.6 $ 24.4 Operating Income 15.3 16.1 16.5 Net Income 10.3 10.6 10.6 Balance Sheet Data: Current Assets 12.1 12.0 12.5 Noncurrent Assets 155.5 157.4 160.2 Current Liabilities 19.3 17.1 18.3 Noncurrent Liabilities 68.5 77.4 85.7 Total Members’ Equity 79.8 74.9 68.7 Contribution/Distribution Data: (1) Contributions to Hardy Storage — — — Distribution of earnings from Hardy Storage 2.6 2.2 3.1 Pennant Statement of Operations Data: Net Revenues $ 34.6 $ 8.5 $ 2.0 Operating Income (Loss) 17.8 (2.4 ) 1.3 Net Income (Loss) 17.8 (2.4 ) 1.3 Balance Sheet Data: Current Assets 11.0 23.7 34.1 Noncurrent Assets 389.6 380.0 231.9 Current Liabilities 8.4 8.6 11.4 Total Members’ Equity 392.2 395.1 254.6 Contribution/Distribution Data: (1) Contributions to Pennant — 66.6 108.9 Distribution of earnings from Pennant 7.1 — — Return of capital from Pennant 16.0 — — (1) Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule Of Components Of Income Tax Expense	Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Income Taxes Current Federal $ 12.0 $ 21.3 $ (16.1 ) State 1.2 5.8 (11.4 ) Total Current 13.2 27.1 (27.5 ) Deferred Federal 8.8 117.7 155.9 State 1.9 21.7 24.1 Total Deferred 10.7 139.4 180.0 Deferred Investment Credits — (0.1 ) (0.1 ) Total Income Taxes $ 23.9 $ 166.4 $ 152.4
Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes	Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Book income before income taxes $ 554.1 $ 435.5 $ 419.3 Tax expense at statutory federal income tax rate 193.9 35.0 % 152.4 35.0 % 146.8 35.0 % Increases (reductions) in taxes resulting from: State income taxes, net of federal income tax benefit 2.0 0.4 17.9 4.1 8.2 1.9 Income not subject to income tax at the partnership level (170.6 ) (30.9 ) — — — — AFUDC-Equity (0.3 ) — (3.8 ) (0.9 ) (2.4 ) (0.6 ) Other, net (1.1 ) (0.2 ) (0.1 ) — (0.2 ) — Total Income Taxes $ 23.9 4.3 % $ 166.4 38.2 % $ 152.4 36.3 %
Schedule Of Principal Components Of Net Deferred Tax Liability	At December 31, (in millions) 2015 2014 Predecessor Deferred tax liabilities Accelerated depreciation and other property differences $ 1.0 $ 1,235.3 Pension and other postretirement/postemployment benefits — 24.3 Other regulatory assets — 62.8 Other, net — 77.9 Total Deferred Tax Liabilities 1.0 1,400.3 Deferred tax assets Deferred investment tax credits and other regulatory liabilities — (116.7 ) Net operating loss carryforward and AMT credit carryforward — (67.8 ) Other accrued liabilities — (1.4 ) Total Deferred Tax Assets — (185.9 ) Net Deferred Tax Liabilities less Deferred Tax Assets 1.0 1,214.4 Less: Deferred income taxes related to current assets and liabilities — (24.6 ) Non-Current Deferred Tax Liabilities $ 1.0 $ 1,239.0

Pension And Other Postretirem46

Pension And Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
Pension and Other Postretirement Benefit Expense [Abstract]
Schedule Of Allocation of Plan Assets	Defined Benefit Pension Plan Postretirement Benefit Plan Asset Category Minimum Maximum Minimum Maximum Domestic Equities 25% 45% 35% 55% International Equities 15% 25% 15% 25% Fixed Income 23% 37% 20% 50% Real Estate/Private Equity/Hedge Funds 0% 15% 0% 0% Short-Term Investments 0% 10% 0% 10% Pension Plan and Postretirement Plan Asset Mix at December 31, 2015 and December 31, 2014 : December 31, 2015 Defined Benefit Postretirement Asset Class Asset Value % of Total Assets Asset Value % of Total Assets (in millions) (in millions) Domestic Equities $ 115.9 39.4 % $ 95.3 44.6 % International Equities 51.4 17.5 % 40.1 18.7 % Fixed Income 101.5 34.4 % 71.8 33.6 % Cash/Other 25.5 8.7 % 6.7 3.1 % Total $ 294.3 100.0 % $ 213.9 100.0 % December 31, 2014 Defined Benefit Postretirement Asset Class Asset Value % of Total Assets Asset Value % of Total Assets (in millions) (in millions) Domestic Equities $ 125.2 41.1 % $ 99.9 47.2 % International Equities 55.0 18.1 % 38.9 18.4 % Fixed Income 105.0 34.4 % 72.2 34.1 % Real Estate/Private Equity/Hedge Funds 15.4 5.0 % — — % Cash/Other 4.2 1.4 % 0.6 0.3 % Total $ 304.8 100.0 % $ 211.6 100.0 %
Schedule Of Fair Value and Changes In The Fair Value Of The Plan Assets	Fair Value Measurements (in millions) December 31, Quoted Prices in Active Significant Other Significant Pension plan assets Cash $ 0.8 $ 0.8 $ — $ — Equity securities International equities 5.4 5.4 — — Fixed income securities Government 7.1 — 7.1 — Corporate 10.8 — 10.8 — Commingled funds Short-term money markets 25.5 — 25.5 — U.S. equities 115.9 — 115.9 — International equities 45.7 — 45.7 — Fixed income 83.1 — 83.1 — Pension plan assets subtotal 294.3 6.2 288.1 — Other postretirement benefit plan assets Commingled funds Short-term money markets 6.8 — 6.8 — U.S. equities 13.0 — 13.0 — Mutual funds U.S. equities 82.3 82.3 — — International equities 40.1 40.1 — — Fixed income 71.7 71.7 — — Other postretirement benefit plan assets subtotal 213.9 194.1 19.8 — Due to brokers, net (1) (0.3 ) Accrued investment income/dividends 0.5 Total pension and other postretirement benefit plan assets $ 508.4 $ 200.3 $ 307.9 $ — (1) This class represents pending trades with brokers. The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2015 : (in millions) Balance at January 1, 2015 Total gains or losses (unrealized / realized) Purchases (Sales) Transfers into/(out of) level 3 Separation Allocation (1) Balance at December 31, 2015 Fixed income securities Other fixed income $ 0.1 $ — $ — $ — $ — $ (0.1 ) $ — Private equity limited partnerships U.S. multi-strategy 7.3 — — — — (7.3 ) — International multi-strategy 4.6 — — — — (4.6 ) — Distressed opportunities 1.0 — — — — (1.0 ) — Real estate 2.3 — — — — (2.3 ) — Total $ 15.3 $ — $ — $ — $ — $ (15.3 ) $ — (1) Level 3 assets were not contributed to the Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation. The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts: Fair Value Measurements (in millions) December 31, Quoted Prices in Active Significant Other Significant Pension plan assets Cash $ 2.2 $ 2.2 $ — $ — Equity securities International equities 17.6 17.5 0.1 — Fixed income securities Government 15.5 13.7 1.8 — Corporate 33.6 — 33.6 — Mortgages/Asset backed securities 0.4 — 0.4 — Other fixed income 0.1 — — 0.1 Commingled funds Short-term money markets 4.3 — 4.3 — U.S. equities 125.2 — 125.2 — International equities 36.6 — 36.6 — Fixed income 53.5 — 53.5 — Private equity limited partnerships U.S. multi-strategy (1) 7.3 — — 7.3 International multi-strategy (2) 4.6 — — 4.6 Distressed opportunities 1.0 — — 1.0 Real Estate 2.3 — — 2.3 Pension plan assets subtotal 304.2 33.4 255.5 15.3 Other postretirement benefit plan assets Commingled funds Short-term money markets 0.7 — 0.7 — U.S. equities 13.6 — 13.6 — Mutual funds U.S. equities 86.4 86.4 — — International equities 38.9 38.9 — — Fixed income 72.0 72.0 — — Other postretirement benefit plan assets subtotal 211.6 197.3 14.3 — Due to brokers, net (3) (0.1 ) Accrued investment income/dividends 0.1 Net receivables 0.6 Total pension and other postretirement benefit plan assets $ 516.4 $ 230.7 $ 269.8 $ 15.3 (1) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily in the United States. (2) This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States. (3) This class represents pending trades with brokers. The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2014 : (in millions) Balance at January 1, 2014 Total gains or losses (unrealized / realized) Purchases (Sales) Transfers into/(out of) level 3 Balance at December 31, 2014 Fixed income securities Other fixed income $ — $ — $ 0.1 $ — $ — $ 0.1 Private equity limited partnerships U.S. multi-strategy 7.6 0.3 0.3 (0.9 ) — 7.3 International multi-strategy 5.0 (0.1 ) 0.1 (0.4 ) — 4.6 Distress opportunities 1.2 — — (0.2 ) — 1.0 Real estate 2.6 0.3 — (0.6 ) — 2.3 Total $ 16.4 $ 0.5 $ 0.5 $ (2.1 ) $ — $ 15.3
Schedule Of Reconciliation Of The Plan Funded Status	Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2015 2014 Predecessor Predecessor Change in projected benefit obligation (1) Benefit obligation at beginning of year $ 345.2 $ 327.1 $ 108.9 $ 105.5 Service cost 5.3 4.8 1.0 1.1 Interest cost 12.5 13.7 4.0 4.6 Plan participants’ contributions — — 1.6 1.9 Actuarial loss (gain) (7.3 ) 20.0 (11.6 ) 4.6 Benefits paid (23.5 ) (20.4 ) (7.5 ) (9.1 ) Estimated benefits paid by incurred subsidy — — 0.2 0.3 Contributed/noncontributed projected benefit obligation (2) (4.6 ) — (3.2 ) — Projected benefit obligation at end of year $ 327.6 $ 345.2 $ 93.4 $ 108.9 Change in plan assets Fair value of plan assets at beginning of year $ 304.7 $ 299.1 $ 211.6 $ 198.8 Actual return on plan assets 0.6 19.3 (2.0 ) 9.2 Employer contributions 16.5 6.7 11.3 10.8 Plan participants’ contributions — — 1.6 1.9 Benefits paid (23.5 ) (20.4 ) (7.5 ) (9.1 ) Contributed/noncontributed plan assets (2) (4.0 ) — (1.1 ) — Fair value of plan assets at end of year $ 294.3 $ 304.7 $ 213.9 $ 211.6 Funded status at end of year $ (33.3 ) $ (40.5 ) $ 120.5 $ 102.7 Amounts recognized in the statement of financial position consist of: Noncurrent assets $ — $ — $ 120.5 $ 109.8 Current liabilities (0.1 ) — — — Noncurrent liabilities (33.2 ) (40.5 ) — (7.1 ) Net amount recognized at end of year (3) $ (33.3 ) $ (40.5 ) $ 120.5 $ 102.7 Amounts recognized as regulatory assets/liabilities (4) Unrecognized prior service (credit) cost $ (3.0 ) $ (4.0 ) $ 0.1 $ 0.1 Unrecognized actuarial loss (gain) 130.3 124.5 (0.4 ) (8.3 ) Total recognized regulatory assets (liabilities) $ 127.3 $ 120.5 $ (0.3 ) $ (8.2 ) (1) The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation. (2) Reflects the removal of amounts related to Crossroads Pipeline Company and CPGSC, which 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) The Partnership recognizes in its Consolidated and Combined Balance Sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. (4) The Partnership determined that the future recovery of pension and other postretirement benefits costs is probable. The Partnership recorded regulatory assets and liabilities of $127.1 million and $0.6 million , respectively, as of December 31, 2015 , and $120.9 million and $8.3 million , respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss.
Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan	Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 Predecessor Predecessor Weighted-average assumptions to determine benefit obligation Discount Rate 4.05 % 3.64 % 4.28 % 3.95 % Rate of Compensation Increases 4.00 % 4.00 % Health Care Trend Rates Trend for Next Year 8.38 % 6.90 % Ultimate Trend 4.50 % 4.50 % Year Ultimate Trend Reached 2022 2021
Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates	(in millions) 1% point increase 1% point decrease Effect on service and interest components of net periodic cost $ 0.1 $ (0.1 ) Effect on accumulated postretirement benefit obligation 2.5 (2.3 )
Schedule Of Expected Payments To Participants In Pension Plan	(in millions) Pension Benefits Other Federal Year(s) 2016 $ 27.2 $ 6.2 $ 0.3 2017 27.1 6.2 0.3 2018 27.9 6.3 0.3 2019 28.0 6.4 0.3 2020 30.0 6.4 0.3 2021-2025 145.8 31.4 1.2
Components Of The Plans' Net Periodic Benefits Cost	Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2013 2015 2014 2013 Predecessor Predecessor Predecessor Predecessor Components of Net Periodic Benefit Cost (Income) Service cost $ 5.3 $ 4.8 $ 4.8 $ 1.0 $ 1.1 $ 1.5 Interest cost 12.5 13.7 12.6 4.0 4.6 4.9 Expected return on assets (23.6 ) (23.8 ) (22.0 ) (17.4 ) (16.5 ) (13.5 ) Amortization of prior service (credit) cost (0.9 ) (1.0 ) (0.9 ) 0.1 0.1 0.1 Recognized actuarial loss (gain) 8.2 6.6 10.6 (0.2 ) (0.1 ) 1.0 Net Periodic Benefit Cost (Income) 1.5 0.3 5.1 (12.5 ) (10.8 ) (6.0 ) Settlement loss — — 12.4 — — — Total Net Periodic Benefit Cost (Income) $ 1.5 $ 0.3 $ 17.5 $ (12.5 ) $ (10.8 ) $ (6.0 )
Schedule Of Key Assumptions That Were Used To Calculate The Net Periodic Benefits Cost	Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Predecessor Predecessor Predecessor Predecessor Weighted-average assumptions to determine net periodic benefit cost Discount Rate 3.84 % 4.34 % 3.36 % 4.09 % 4.74 % 3.92 % Expected Long-Term Rate of Return on Plan Assets 8.20 % 8.30 % 8.30 % 8.06 % 8.14 % 8.15 % Rate of Compensation Increases 4.00 % 4.00 % 4.00 %
Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income	Pension Benefits Other Postretirement Benefits (in millions) 2015 2014 2015 2014 Predecessor Predecessor Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities Net actuarial loss $ 14.1 $ 24.4 $ 7.8 $ 11.7 Less: amortization of prior service (credit) cost 0.9 1.0 (0.1 ) — Less: amortization of net actuarial (gain) loss (8.2 ) (6.6 ) 0.2 — Total recognized in regulatory assets/liabilities $ 6.8 $ 18.8 $ 7.9 $ 11.7 Amount recognized in net periodic benefit cost and regulatory assets/liabilities $ 8.3 $ 19.1 $ (4.6 ) $ 0.9

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Carrying Amount And Estimated Fair Values Of Financial Instruments	At December 31, (in millions) Carrying Amount 2015 Estimated Fair Value 2015 Carrying Amount 2014 Estimated Fair Value 2014 Predecessor Current portion of long-term debt-affiliated $ — $ — $ 115.9 $ 120.0 Long-term debt-affiliated 630.9 630.9 1,472.8 1,550.4

Other Commitments And Conting48

Other Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The total guarantees and indemnities in existence at December 31, 2015 and the years in which they expire were: (in millions) Total 2016 2017 2018 2019 2020 After Guarantees of debt $ 2,750.0 $ — $ — $ 500.0 $ — $ 750.0 $ 1,500.0 Letters of credit 18.1 18.1 — — — — — Total commercial commitments $ 2,768.1 $ 18.1 $ — $ 500.0 $ — $ 750.0 $ 1,500.0
Future Minimum Lease Payments Required Under Operating And Capital Leases	(in millions) Operating Leases (1) 2016 $ 4.5 2017 5.9 2018 5.5 2019 4.8 2020 4.7 After 21.2 Total future minimum payments $ 46.6 (1) Operating lease expense includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.
Estimated Aggregate Amounts Of Minimum Fixed Payments On Purchase And Service Obligations	(in millions) Pipeline Service Agreements 2016 $ 51.5 2017 49.5 2018 42.0 2019 25.4 2020 24.2 After 66.8 Total future minimum payments $ 259.4

Accumulated Other Comprehensi49

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2015
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	(in millions) Gains and Losses on Cash Flow Hedges (1) Pension and OPEB Items (1) Accumulated Other Comprehensive Loss (1) Balance as of January 1, 2013 - Predecessor $ (18.7 ) $ (0.1 ) $ (18.8 ) Other comprehensive income before reclassifications — — — Amounts reclassified from accumulated other comprehensive income 1.1 — 1.1 Net current-period other comprehensive income 1.1 — 1.1 Balance as of December 31, 2013 - Predecessor $ (17.6 ) $ (0.1 ) $ (17.7 ) Other comprehensive income before reclassifications — — — Amounts reclassified from accumulated other comprehensive income 1.0 — 1.0 Net current-period other comprehensive income 1.0 — 1.0 Balance as of December 31, 2014 - Predecessor $ (16.6 ) $ (0.1 ) $ (16.7 ) Predecessor net tax liabilities not assumed by Columbia OpCo (2) $ (10.2 ) $ (0.1 ) (10.3 ) Other comprehensive income before reclassifications — (0.3 ) (0.3 ) Amounts reclassified from accumulated other comprehensive income (3) 1.5 0.1 1.6 Net current-period other comprehensive income 1.5 (0.2 ) 1.3 Allocation of accumulated other comprehensive loss to noncontrolling interest (21.4 ) (0.3 ) (21.7 ) Balance as of December 31, 2015 $ (3.9 ) $ (0.1 ) $ (4.0 ) (1) All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits. (2) 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. (3) Includes amounts allocated to noncontrolling interest.

Other, Net (Tables)

Other, Net (Tables)	12 Months Ended
	Dec. 31, 2015
Other Nonoperating Income (Expense) [Abstract]
Schedule Of Other, Net	Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor AFUDC Equity $ 28.3 $ 11.0 $ 6.8 Miscellaneous (1) 3.7 (2.2 ) 10.8 Total Other, net $ 32.0 $ 8.8 $ 17.6 (1) Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

Supplemental Cash Flow Inform51

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Year Ended December 31, (in millions) 2015 2014 2013 Predecessor Predecessor Supplemental Disclosures of Cash Flow Information Non-cash transactions: Capital expenditures included in current liabilities (1) $ 122.7 $ 78.5 $ 53.1 Schedule of interest and income taxes paid: Cash paid for interest, net of interest capitalized amounts $ 40.3 $ 53.6 $ 39.5 Cash paid for income taxes 0.2 21.5 10.2 (1) Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated and Combined Balance Sheets.

Concentration of Credit Risk (T

Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk, by Risk Factor	Year Ended December 31, 2015 2014 2013 (in millions) Total Operating Revenues Percentage of Total Operating Revenues Total Operating Revenues Percentage of Total Operating Revenues Total Operating Revenues Percentage of Total Operating Revenues Predecessor Predecessor Columbia Gas of Ohio (1) $ 167.3 12.6 % $ 168.5 12.5 % $ 167.5 14.2 % (1) Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release arrangements with third parties which ultimately can decrease the net revenue amount we receive from Columbia Gas of Ohio in any given period.

Quarterly Financial Data (Una53

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Schedule Of Quarterly Financial Data	(in millions, except per unit data) First Quarter Second Quarter Third Quarter Fourth Quarter 2015 Operating Revenues $ 339.2 $ 315.6 $ 320.0 $ 357.0 Operating Income 162.0 109.2 142.8 136.3 Net Income 131.2 107.8 144.6 146.6 Predecessor net income prior to IPO on February 11, 2015 42.7 — — — Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO 75.2 91.5 122.6 124.2 Net income attributable to limited partners subsequent to IPO 13.3 16.3 22.0 22.4 Net Income Per Limited Partner Unit (basic and diluted) Common Units 0.13 0.17 0.22 0.22 Subordinated Units 0.13 0.16 0.22 0.22 2014 Operating Revenues $ 345.5 $ 343.4 $ 317.6 $ 340.4 Operating Income 158.5 103.2 93.8 133.2 Net Income 92.5 59.0 53.2 64.4

Nature Of Operations And Summ54

Nature Of Operations And Summary Of Significant Accounting Policies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)mi	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Basis Of Accounting Presentation [Line Items]
Pipeline Length | mi	15,000
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	15.70%
Base Gas Purchases	$ 0	$ 0	$ 0
Amortized software costs	5.8	4.3	5
Unamortized software costs	27.1	18.3
Goodwill	1,975.5
Asset Impairment Charges	0.6	0	0
Royalty Revenue	26.5	43.8	21.2
Gain on Conveyances	52.3	34.5	$ 7.3
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 0.3
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects	1
Joint Ventures [Member]
Basis Of Accounting Presentation [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	84.30%
Millennium Pipeline
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Ownership Percentage	47.50%
Hardy Storage
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Pennant
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Initial Ownership Percentage	5.00%
Equity Method Investment, Ownership Percentage	47.50%
Cash Received from Buy-In	$ 12.7
Gain on Buy-In	$ 2.9
Maximum | Pennant
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Previous [Member] | Pennant
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Predecessor
Basis Of Accounting Presentation [Line Items]
Goodwill		$ 1,975.5
Predecessor | Hardy Storage
Basis Of Accounting Presentation [Line Items]
Equity Method Investment, Ownership Percentage		50.00%

Nature Of Operations And Summ55

Nature Of Operations And Summary Of Significant Accounting Policies (Schedule of AFUDC Debt and Equity Rates) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Rate | Columbia Gas Transmission
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate	1.80%
Debt Rate | Columbia Gulf
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate	2.90%
Debt Rate | Predecessor | Columbia Gas Transmission
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate		0.90%	2.50%
Debt Rate | Predecessor | Columbia Gulf
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate		2.10%	2.50%
Equity Rate | Columbia Gas Transmission
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate	6.30%
Equity Rate | Columbia Gulf
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate	6.30%
Equity Rate | Predecessor | Columbia Gas Transmission
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate		3.00%	3.20%
Equity Rate | Predecessor | Columbia Gulf
Schedule of AFUDC Debt and Equity Rates [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Rate		9.40%	3.20%

Nature Of Operations And Summ56

Nature Of Operations And Summary Of Significant Accounting Policies (Schedule of Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Beginning Balance	$ 14.9	$ 1.9
Additions Pending the Determination of Proved Reserves	1.3	20.1
Reclassification of Proved Reserves	(14.5)	(7.1)
Ending Balance	$ 1.7	$ 14.9

Initial Public Offering (Narrat

Initial Public Offering (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 11, 2015	Dec. 31, 2015	Dec. 31, 2015
Initial Public Offering [Line Items]
Contribution of capital from parent	$ 1,217.3
Net proceeds from IPO		$ 1,168.4
Payments of Stock Issuance Costs		$ 69.8
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest			15.70%
Common Units
Initial Public Offering [Line Items]
Shares Issued, Price Per Share	$ 23
Partners' Capital Account, Units, Sold in Public Offering		53,833,107
Over-Allotment Option [Member] | Common Units
Initial Public Offering [Line Items]
Partners' Capital Account, Units, Sold in Public Offering		7,021,709
Columbia Energy Group
Initial Public Offering [Line Items]
Contribution of capital from parent	$ 1,217.3
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		7.30%
Columbia Energy Group | Subordinated Units
Initial Public Offering [Line Items]
Partners' Capital Account, Units, Sold in Public Offering		46,811,398
Columbia OpCo
Initial Public Offering [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest Additional Ownership Interest		8.40%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		15.70%
Reimbursement of Preformation Capital		$ 500
Limited Partner | Common Units
Initial Public Offering [Line Items]
Contribution of capital from parent	0
Net proceeds from IPO		1,168.4
Limited Partner | Subordinated Units
Initial Public Offering [Line Items]
Contribution of capital from parent	$ 0
Net proceeds from IPO		$ 0
Limited Partner | Columbia Energy Group
Initial Public Offering [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		84.30%

Initial Public Offering (Schedu

Initial Public Offering (Schedule fo Change From Net Income Attributable to the Partnership and Transfers to Noncontrolling Interest) (Details) - USD ($) $ in Millions	2 Months Ended	3 Months Ended			11 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2015
Initial Public Offering [Line Items]
Net Income (Loss) Allocated to Limited Partners	$ 13.3	$ 22.4	$ 22	$ 16.3	$ 74	$ 74
Noncontrolling Interest, Increase from Subsidiary Equity Issuance					0
Change from net income attributable to the Partnership and transfers to noncontrolling interest					(350.4)
Noncontrolling Interest
Initial Public Offering [Line Items]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance					$ (424.4)

Partners' Equity and Cash Dis59

Partners' Equity and Cash Distributions (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Distribution Made to Limited Partner [Line Items]
Subordination Period End Percentage	150.00%
First
Distribution Made to Limited Partner [Line Items]
Minimum Quarterly Distribution, Per Unit	$ 0.192625
Second
Distribution Made to Limited Partner [Line Items]
Minimum Quarterly Distribution, Per Unit	0.209375
Third
Distribution Made to Limited Partner [Line Items]
Minimum Quarterly Distribution, Per Unit	0.251250
Final
Distribution Made to Limited Partner [Line Items]
Minimum Quarterly Distribution, Per Unit	$ 0.251250
Common and Subordinated | Second
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	85.00%
Common and Subordinated | Third
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	75.00%
Common and Subordinated | Final
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	50.00%
Columbia Energy Group | Second
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	15.00%
Columbia Energy Group | Third
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	25.00%
Columbia Energy Group | Final
Distribution Made to Limited Partner [Line Items]
Pro Rata Percentage of Distribution in Excess of Minimum	50.00%

Partners' Equity and Cash Dis60

Partners' Equity and Cash Distributions (Schedule of Cash Distributions) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	[1]
Equity [Abstract]
Distribution Made to Limited Partner, Date of Record	Feb. 11, 2016	Nov. 13, 2015	Aug. 13, 2015	May 13, 2015
Distribution Made to Limited Partner, Distribution Date	Feb. 19, 2016	Nov. 20, 2015	Aug. 20, 2015	May 20, 2015
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.1800	$ 0.1725	$ 0.1675	$ 0.0912
Distribution Made to Limited Partner, Cash Distributions Paid	$ 18.1	$ 17.4	$ 16.9	$ 9.2
[1]	The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.

Net Income Per Limited Partne61

Net Income Per Limited Partner Unit (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 29, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	[1]	Dec. 31, 2015
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.1800	$ 0.1725	$ 0.1675	$ 0.0912
Distribution Made to Limited Partner, Distribution Date		Feb. 19, 2016	Nov. 20, 2015	Aug. 20, 2015	May 20, 2015
Distribution Made to Limited Partner, Date of Record		Feb. 11, 2016	Nov. 13, 2015	Aug. 13, 2015	May 13, 2015
Minimum
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit							$ 0.1675
Annualized [Member] | Minimum
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit							$ 0.67
Subsequent Event
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.1800
Distribution Made to Limited Partner, Cash Distributions Declared	$ 18.1
Distribution Made to Limited Partner, Distribution Date	Feb. 19, 2016
Distribution Made to Limited Partner, Date of Record	Feb. 11, 2016
[1]	The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.

Net Income Per Limited Partne62

Net Income Per Limited Partner Unit (Schedule of Net Income Per Limited Partner Unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		2 Months Ended	3 Months Ended				11 Months Ended	12 Months Ended
		Mar. 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2015
Schedule Of Earnings Per Unit [Line Items]
Partners' Capital Account, Distributions								$ 61.6
Undistributed Earnings, Basic	[1]							12.4
Net Income (Loss) Allocated to Limited Partners		$ 13.3	$ 22.4	$ 22	$ 16.3		$ 74	$ 74
Weighted Average Number of Shares Outstanding, Basic and Diluted								100.6
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax								$ 0.74
Common Units
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared								$ 32.9
Undistributed Earnings, Basic	[1]							6.7
Net Income (Loss) Allocated to Limited Partners								$ 39.6
Weighted Average Number of Shares Outstanding, Basic and Diluted								53.8
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax			$ 0.22	$ 0.22	$ 0.17	$ 0.13		$ 0.74
Subordinated Units
Schedule Of Earnings Per Unit [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared								$ 28.7
Undistributed Earnings, Basic	[1]							5.1
Net Income (Loss) Allocated to Limited Partners								$ 33.8
Weighted Average Number of Shares Outstanding, Basic and Diluted								46.8
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax			$ 0.22	$ 0.22	$ 0.16	$ 0.13		$ 0.72
Incentive Distribution Rights
Schedule Of Earnings Per Unit [Line Items]
Incentive Distribution, Distribution								$ 0
Undistributed Earnings, Basic	[1]							0.6
Net Income (Loss) Allocated to Limited Partners								$ 0.6
[1]	Net income attributable to partners in excess of distribution is for the period subsequent to the IPO.

Transactions With Affiliates (N

Transactions With Affiliates (Narrative) (Details) - USD ($) $ in Millions	11 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 05, 2014
Related Party Transaction [Line Items]
Interest Expense, Long-term Debt		$ 35.1
Allowance for Funds Used During Construction, Capitalized Interest		$ 9.2
Short-term Debt, Weighted Average Interest Rate	1.21%	1.21%
Interest Expense, Short-term Borrowings		$ 0.9
Accounts Receivable	$ 149.4	149.4
Line of Credit Facility, Maximum Borrowing Capacity	2,600	2,600
Default Provision Floor	50	50
Short-term borrowings-affiliated	42.1	42.1
Distribution to Parent		687.3
Transportation and Storage Services
Related Party Transaction [Line Items]
Accounts Receivable	8.9	8.9
Predecessor
Related Party Transaction [Line Items]
Interest Expense, Long-term Debt			$ 61.6	$ 40.6
Allowance for Funds Used During Construction, Capitalized Interest			$ 2.7	6.8
Short-term Debt, Weighted Average Interest Rate			0.70%
Interest Expense, Short-term Borrowings			$ 3.1	4.1
Accounts Receivable			153.8
Short-term borrowings-affiliated			247.3
Distribution to Parent			0	$ 113
Predecessor | Transportation and Storage Services
Related Party Transaction [Line Items]
Accounts Receivable			28.8
Money Pool
Related Party Transaction [Line Items]
Accounts Receivable	140.5	140.5
Line of Credit Facility, Maximum Borrowing Capacity	750	750
Money Pool | Predecessor
Related Party Transaction [Line Items]
Accounts Receivable			$ 125
Revolving Credit Facility
Related Party Transaction [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500	500			$ 1,500
Notes Due 2020
Related Party Transaction [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,300	$ 2,300
Debt Instrument, Interest Rate, Stated Percentage	4.70%	4.70%
Debt Instrument, Maturity Date		Dec. 31, 2020
Columbia OpCo
Related Party Transaction [Line Items]
Reimbursement of Preformation Capital	$ 500
London Interbank Offered Rate (LIBOR)
Related Party Transaction [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%

Transactions With Affiliates (S

Transactions With Affiliates (Schedule of Affiliated Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Transportation revenues	$ 47.1
Storage revenues	26.2
Other revenues	0.2
Operation and maintenance expense	164.1
Interest expense	26.8
Interest Income	4.8
Accounts Receivable	149.4
Current portion of long-term debt	0
Short-term borrowings	42.1
Accounts Payable	86.3
Long-term Debt	$ 630.9
Predecessor
Related Party Transaction [Line Items]
Transportation revenues		$ 95.8	$ 94.3
Storage revenues		53.2	53.6
Other revenues		0.3	0.3
Operation and maintenance expense		122.9	118.1
Interest expense		62	37.9
Interest Income		0.5	$ 0.5
Accounts Receivable		153.8
Current portion of long-term debt		115.9
Short-term borrowings		247.3
Accounts Payable		49.9
Long-term Debt		$ 1,472.8

Transactions With Affiliates 65

Transactions With Affiliates (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt		$ 630.9
Notes Due 2015
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2005
Debt Instrument, Interest Rate, Stated Percentage		5.41%
Debt Instrument, Maturity Date		Nov. 30, 2015
Long-term Debt	[1]	$ 0
Notes Due 2016
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2005
Debt Instrument, Interest Rate, Stated Percentage		5.45%
Debt Instrument, Maturity Date		Nov. 28, 2016
Long-term Debt		$ 0
Notes Due 2025
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2005
Debt Instrument, Interest Rate, Stated Percentage		5.92%
Debt Instrument, Maturity Date		Nov. 28, 2025
Long-term Debt		$ 0
Notes Due 2032
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2012
Debt Instrument, Interest Rate, Stated Percentage		4.63%
Debt Instrument, Maturity Date		Nov. 28, 2032
Long-term Debt		$ 0
Notes Due 2037
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2012
Debt Instrument, Interest Rate, Stated Percentage		4.94%
Debt Instrument, Maturity Date		Nov. 30, 2037
Long-term Debt		$ 0
Notes Due 2037 [1]
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Dec. 19, 2012
Debt Instrument, Interest Rate, Stated Percentage		5.16%
Debt Instrument, Maturity Date		Dec. 21, 2037
Long-term Debt		$ 0
Notes Due 2042
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Nov. 28, 2012
Debt Instrument, Interest Rate, Stated Percentage		5.26%
Debt Instrument, Maturity Date		Nov. 28, 2042
Long-term Debt		$ 0
Notes Due 2042 [1]
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Dec. 19, 2012
Debt Instrument, Interest Rate, Stated Percentage		5.49%
Debt Instrument, Maturity Date		Dec. 18, 2042
Long-term Debt		$ 0
Notes Due 2020
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Debt Instrument, Issuance Date		Dec. 9, 2013
Debt Instrument, Interest Rate, Stated Percentage		4.70%
Debt Instrument, Maturity Date		Dec. 31, 2020
Long-term Debt	[2]	$ 630.9
Predecessor
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			$ 1,588.7
Predecessor | Notes Due 2015
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt	[1]		115.9
Predecessor | Notes Due 2016
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			45.3
Predecessor | Notes Due 2025
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			133.5
Predecessor | Notes Due 2032
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			45
Predecessor | Notes Due 2037
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			95
Predecessor | Notes Due 2037 [1]
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			55
Predecessor | Notes Due 2042
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			170
Predecessor | Notes Due 2042 [1]
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt			95
Predecessor | Notes Due 2020
Schedule of Related Party Transactions, Long-Term Debt [Line Items]
Long-term Debt	[2]		$ 834
[1]	The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in "Current portion of long-term debt-affiliated" on the Combined Balance Sheet as of December 31, 2014.
[2]	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

Short-Term Borrowings (Narrativ

Short-Term Borrowings (Narrative) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)	Dec. 05, 2014USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,600
Default Provision Floor	50
Letters Of Credit
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	0
Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Amount Outstanding	$ 15	$ 0
Federal Funds Effective Swap Rate [Member]
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
London Interbank Offered Rate (LIBOR)
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Minimum
Short-term Debt [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.125%
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares	$ 0.1675
Minimum | London Interbank Offered Rate (LIBOR)
Short-term Debt [Line Items]
Margin Rate	0.00%
Minimum | Eurodollar [Member]
Short-term Debt [Line Items]
Margin Rate	1.00%
Maximum
Short-term Debt [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.35%
Maximum | London Interbank Offered Rate (LIBOR)
Short-term Debt [Line Items]
Margin Rate	0.65%
Maximum | Eurodollar [Member]
Short-term Debt [Line Items]
Margin Rate	1.65%
Period 1 | Minimum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	5.75
Period 1 | Maximum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	1
Period 2 | Minimum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	5.50
Period 2 | Maximum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	1
Period 3 | Minimum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	5
Period 3 | Maximum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	1
Acquisition Period | Minimum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	5.50
Acquisition Period | Maximum
Short-term Debt [Line Items]
Ratio of Indebtedness to Net Capital	1
Letters Of Credit
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 50
Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500		$ 1,500

Short-Term Borrowings (Schedule

Short-Term Borrowings (Schedule Of Short-Term Borrowings) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate	1.21%
Credit Facilities [Member]
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate	1.28%	0.00%
Revolving Credit Facility
Short-term Debt [Line Items]
Credit facilities borrowings	$ 15	$ 0

Gain on Sale of Assets (Details

Gain on Sale of Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Gain on Conveyances	$ 52.3	$ 34.5	$ 7.3
Gain on Conveyances Cash Received	35.8
Deferred Gains On Conveyances	8.1	$ 19.6
Gain (Loss) on Disposition of Property Plant Equipment	$ 54.7
Gas Stored Base Gas
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment			$ 11.1

Property, Plant And Equipment69

Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	$ 8,930.9	$ 7,931.6
Accumulated Depreciation and Amortization	(2,960.1)	(2,971.4)
Net Property, Plant and Equipment	5,970.8	4,960.2
Pipeline and Other Transmission Assets
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	6,120	5,328.2
Storage Facilities
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	1,370.1	1,326.5
Gas Stored Base Gas
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	299.5	299.5
Gas Gathering and Processing Equipment
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	370.2	263.3
Construction Work In Process
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	463.5	454.2
General Plant, Software, and Other Assets
Property, Plant and Equipment [Line Items]
Property Plant and Equipment	$ 307.6	$ 259.9

Property, Plant And Equipment70

Property, Plant And Equipment (Schedule of Depreciation Rates) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pipeline and Other Transmission Assets | Minimum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	1.00%	1.00%	1.50%
Pipeline and Other Transmission Assets | Maximum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	1.73%	2.55%	2.55%
Storage Facilities | Minimum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.19%	2.19%	2.19%
Storage Facilities | Maximum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	3.00%	3.30%	3.50%
Gas Gathering and Processing Facilities | Minimum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	1.67%	1.67%	1.67%
Gas Gathering and Processing Facilities | Maximum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.50%	2.50%	2.50%
General Plant, Software, and Other Assets | Minimum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	1.00%	1.00%	1.00%
General Plant, Software, and Other Assets | Maximum
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	10.00%	10.00%	10.00%

Goodwill (Details)

Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Goodwill And Other Intangible Assets [Line Items]
Goodwill	$ 1,975.5
Goodwill, Impairment Loss	$ 0
Columbia Gas Transmission
Goodwill And Other Intangible Assets [Line Items]
Fair Value Inputs, Discount Rate	5.60%
Fair value amount above carrying value of goodwill	$ 1,643

Asset Retirement Obligations (C

Asset Retirement Obligations (Changes In Company's Liability For Asset Retirement Obligations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Beginning Balance		$ 23.2
Noncontributed net parent investment adjustments	[1]	(0.4)
Accretion expense		1.2
Additions		4.1
Settlements		0
Change in estimated cash flows		2.8
Ending Balance		25.3	$ 23.2
Predecessor
Beginning Balance		$ 23.2	26.3
Noncontributed net parent investment adjustments	[1]		0
Accretion expense			1.5
Additions			2.2
Settlements			(6.6)
Change in estimated cash flows			0.2
Ending Balance			$ 23.2
[1]	Reflects the removal of amounts related to Crossroads Pipeline Company, which was included in the Predecessor, but was not contributed to the Partnership.

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions	Jan. 28, 2016	Jan. 01, 2015	Jan. 24, 2013	Dec. 31, 2015
Regulatory Matters [Line Items]
Regulatory asset not earning return on investment				$ 0
Expenses recovered as components of cost of service and regulatory orders				$ 7.2
Remaining life for the costs to be recovered, years				7 years
Customer Refund			$ 88.1
Initial Customer Refund			50
Annual base rate reduction effective January 1, 2014			$ 25
Capital Cost Recovery Mechanism Revenue Requirement			14.00%
Required Annual Capital Maintenance Expenditure			$ 100
Annual Capital Cost Recovery Mechanism Limit			$ 1,500
Annual Capital Cost Recovery Mechanism Limit Tolerance			15.00%
Total Capital Cost Recovery Mechanism Over Five-year Term			$ 1,500
Depreciation Rate Reduction			1.50%
Expected Modernization Investment		$ 300
Subsequent Event
Regulatory Matters [Line Items]
Expected Modernization Investment	$ 937.1

Regulatory Matters (Regulatory

Regulatory Matters (Regulatory Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 139.1
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	127.1
Other Postretirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	8.9
Deferred Taxes on AFUDC Equity
Regulatory Assets [Line Items]
Total Regulatory Assets	0
Other Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 3.1
Predecessor
Regulatory Assets [Line Items]
Total Regulatory Assets		$ 158
Predecessor | Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Regulatory Assets [Line Items]
Total Regulatory Assets		120.9
Predecessor | Other Postretirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets		10.8
Predecessor | Deferred Taxes on AFUDC Equity
Regulatory Assets [Line Items]
Total Regulatory Assets		21.8
Predecessor | Other Assets
Regulatory Assets [Line Items]
Total Regulatory Assets		$ 4.5

Regulatory Matters (Regulator75

Regulatory Matters (Regulatory Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 310.9
Cost Of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	153.5
Regulatory Effects Of Accounting For Income Taxes
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	0
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	0.6
Other Postretirement Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	155.6
Other Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 1.2
Predecessor
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		$ 295.6
Predecessor | Cost Of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		156.2
Predecessor | Regulatory Effects Of Accounting For Income Taxes
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		10.9
Predecessor | Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		8.3
Predecessor | Other Postretirement Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		117.3
Predecessor | Other Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities		$ 2.9

Equity Method Investments (Narr

Equity Method Investments (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Utilities Operating Expense, Maintenance and Operations	$ 526.1
Millennium Pipeline
Schedule of Equity Method Investments [Line Items]
Utilities Operating Expense, Maintenance and Operations	$ 13.1

Equity Method Investments (Sche

Equity Method Investments (Schedule Of Equity Method Investments) (Details) - LLC Membership	Dec. 31, 2015
Hardy Storage Company, L.L.C.
Schedule of Equity Method Investments [Line Items]
Percentage of voting power held	49.00%
Pennant Midstream, L.L.C.
Schedule of Equity Method Investments [Line Items]
Percentage of voting power held	47.50%
Millennium Pipeline Company, L.L.C
Schedule of Equity Method Investments [Line Items]
Percentage of voting power held	47.50%

Equity Method Investments (Sc78

Equity Method Investments (Schedule Of Immaterial Nature Of Equity Investments) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Feb. 11, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Contribution of capital from parent		$ 1,217.3
Partners' Capital Account, Distributions					$ 113
Millennium Pipeline
Schedule of Equity Method Investments [Line Items]
Net Revenues			$ 206.3
Operating Income			136.1
Net Income			98
Current Assets			35.7
Noncurrent Assets			987.1
Current Liabilities			44.4
Noncurrent Liabilities			535.8
Total Members’ Equity			442.6
Contribution of capital from parent	[1]		1.4
Partners' Capital Account, Distributions	[1]		47.5
Millennium Pipeline | Predecessor
Schedule of Equity Method Investments [Line Items]
Net Revenues				$ 190.5	157.8
Operating Income				128.8	101.3
Net Income				89.6	63
Current Assets				32.1	38.3
Noncurrent Assets				1,016.3	1,033.8
Current Liabilities				42.6	58.8
Noncurrent Liabilities				568.3	599.7
Total Members’ Equity				437.5	413.6
Contribution of capital from parent	[1]			2.6	16.6
Partners' Capital Account, Distributions	[1]			35.6	29
Hardy Storage
Schedule of Equity Method Investments [Line Items]
Net Revenues			23.4
Operating Income			15.3
Net Income			10.3
Current Assets			12.1
Noncurrent Assets			155.5
Current Liabilities			19.3
Noncurrent Liabilities			68.5
Total Members’ Equity			79.8
Contribution of capital from parent	[1]		0
Partners' Capital Account, Distributions	[1]		2.6
Hardy Storage | Predecessor
Schedule of Equity Method Investments [Line Items]
Net Revenues				23.6	24.4
Operating Income				16.1	16.5
Net Income				10.6	10.6
Current Assets				12	12.5
Noncurrent Assets				157.4	160.2
Current Liabilities				17.1	18.3
Noncurrent Liabilities				77.4	85.7
Total Members’ Equity				74.9	68.7
Contribution of capital from parent	[1]			0	0
Partners' Capital Account, Distributions	[1]			2.2	3.1
Pennant
Schedule of Equity Method Investments [Line Items]
Net Revenues			34.6
Operating Income			17.8
Net Income			17.8
Current Assets			11
Noncurrent Assets			389.6
Noncurrent Liabilities			8.4
Total Members’ Equity			392.2
Contribution of capital from parent	[1]		0
Partners' Capital Account, Distributions	[1]		7.1
Partners' Capital Account, Return of Capital	[1]		$ 16
Pennant | Predecessor
Schedule of Equity Method Investments [Line Items]
Net Revenues				8.5	2
Operating Income				(2.4)	1.3
Net Income				(2.4)	1.3
Current Assets				23.7	34.1
Noncurrent Assets				380	231.9
Noncurrent Liabilities				8.6	11.4
Total Members’ Equity				395.1	254.6
Contribution of capital from parent	[1]			66.6	108.9
Partners' Capital Account, Distributions	[1]			0	0
Partners' Capital Account, Return of Capital	[1]			$ 0	$ 0
[1]	Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Income Tax Expense/Benefit [Line Items]
Effective income tax rate	4.30%
Statutory federal income tax rate	35.00%
Unrecognized tax benefits	$ 0
Predecessor
Schedule of Income Tax Expense/Benefit [Line Items]
Effective income tax rate		38.20%	36.30%
Statutory federal income tax rate		35.00%	35.00%
Unrecognized tax benefits		$ 0	$ 0.1

Income Taxes (Schedule Of Compo

Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Federal	$ 12
State	1.2
Total Current	13.2
Deferred
Federal	8.8
State	1.9
Total Deferred	10.7
Deferred Investment Credits	0
Total Income Taxes	$ 23.9
Predecessor
Current
Federal		$ 21.3	$ (16.1)
State		5.8	(11.4)
Total Current		27.1	(27.5)
Deferred
Federal		117.7	155.9
State		21.7	24.1
Total Deferred		139.4	180
Deferred Investment Credits		(0.1)	(0.1)
Total Income Taxes		$ 166.4	$ 152.4

Income Taxes (Schedule Of Reaso

Income Taxes (Schedule Of Reasons Behind Differences In Computation Of Total Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Reasons Behind Differences in Computation of Total Income Taxes [Line Items]
Book income before income taxes	$ 554.1
Tax expense at statutory federal income tax rate, value	$ 193.9
Tax expense at statutory federal income tax rate, rate	35.00%
State income taxes, net of federal income tax benefit, value	$ 2
State income taxes, net of federal income tax benefit, rate	0.40%
Income not subject to income tax at the partnership level, rate	$ (170.6)
Income not subject to income tax at the partnership level, value	(30.90%)
AFUDC-Equity, value	$ (0.3)
AFUDC-Equity, rate	(0.00%)
Other, net, value	$ (1.1)
Other net, rate	(0.20%)
Total Income Taxes	$ 23.9
Total Income Taxes, rate	4.30%
Predecessor
Schedule of Reasons Behind Differences in Computation of Total Income Taxes [Line Items]
Book income before income taxes		$ 435.5	$ 419.3
Tax expense at statutory federal income tax rate, value		$ 152.4	$ 146.8
Tax expense at statutory federal income tax rate, rate		35.00%	35.00%
State income taxes, net of federal income tax benefit, value		$ 17.9	$ 8.2
State income taxes, net of federal income tax benefit, rate		4.10%	1.90%
Income not subject to income tax at the partnership level, rate		$ 0	$ 0
Income not subject to income tax at the partnership level, value		(0.00%)	(0.00%)
AFUDC-Equity, value		$ (3.8)	$ (2.4)
AFUDC-Equity, rate		(0.90%)	(0.60%)
Other, net, value		$ (0.1)	$ (0.2)
Other net, rate		0.00%	0.00%
Total Income Taxes		$ 166.4	$ 152.4
Total Income Taxes, rate		38.20%	36.30%

Income Taxes (Schedule Of Princ

Income Taxes (Schedule Of Principal Components Of Net Deferred Tax Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Principal Components of Net Deferred Tax Liability [Line Items]
Accelerated depreciation and other property differences	$ 1
Pension and other postretirement/postemployment benefits	0
Other regulatory assets	0
Other, net	0
Total Deferred Tax Liabilities	1
Deferred investment tax credits and other regulatory liabilities	0
Net operating loss carryforward and AMT credit carryforward	0
Other accrued liabilities	0
Total Deferred Tax Assets	0
Deferred Tax Liabilities, Net	1
Less: Deferred income taxes related to current assets and liabilities	0
Non-Current Deferred Tax Liability	$ 1
Predecessor
Schedule of Principal Components of Net Deferred Tax Liability [Line Items]
Accelerated depreciation and other property differences		$ 1,235.3
Pension and other postretirement/postemployment benefits		24.3
Other regulatory assets		62.8
Other, net		77.9
Total Deferred Tax Liabilities		1,400.3
Deferred investment tax credits and other regulatory liabilities		(116.7)
Net operating loss carryforward and AMT credit carryforward		(67.8)
Other accrued liabilities		(1.4)
Total Deferred Tax Assets		(185.9)
Deferred Tax Liabilities, Net		1,214.4
Less: Deferred income taxes related to current assets and liabilities		(24.6)
Non-Current Deferred Tax Liability		$ 1,239

Pension And Other Postretirem83

Pension And Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			$ 508.4	$ 516.4
Decrease In Net Periodic Benefit Cost			(1.2)
Accumulated benefit obligation			327.6
Regulatory assets			139.1
Regulatory liabilities			310.9
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			294.3	304.8
Defined Benefit Plan, Actuarial Gain (Loss)	[1]		7.3
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			(0.9)
Defined Benefit Plan, Net Periodic Benefit Cost			1.5
Employer contributions			16.5
Expected contribution			0.1
Funded status of plan			$ (33.3)	(40.5)
Expected return on plan assets			8.20%
Settlement loss			$ 0
Change in Net Periodic Benefit Cost due to Interim Measurement					$ 1.2
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			213.9	211.6
Defined Benefit Plan, Actuarial Gain (Loss)	[1]		11.6
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			0.1
Defined Benefit Plan, Net Periodic Benefit Cost			(12.5)
Employer contributions			11.3
Expected contribution			0.9
Increase in funded status other postretirement benefit plans			17.8
Funded status of plan			$ 120.5
Expected return on plan assets			8.06%
Settlement loss			$ 0
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			$ 0	$ 15.3	16.4
Percentage of investments			0.00%	3.00%
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			$ 0	$ 0
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities			0.6
Scenario, Forecast | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actuarial Gain (Loss)		$ 10.1
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		(0.9)
Amortization of transition obligation		0
Scenario, Forecast | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actuarial Gain (Loss)		0.2
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.1
Amortization of transition obligation		$ 0
Predecessor
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation				345.2
Regulatory assets				158
Regulatory liabilities				295.6
Predecessor | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets				304.7	299.1
Defined Benefit Plan, Actuarial Gain (Loss)	[1]			(20)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				(1)	(0.9)
Defined Benefit Plan, Net Periodic Benefit Cost				0.3	$ 17.5
Employer contributions				6.7
Funded status of plan				$ (40.5)
Expected return on plan assets				8.30%	8.30%
Settlement loss				$ 0	$ 12.4
Predecessor | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets				211.6	198.8
Defined Benefit Plan, Actuarial Gain (Loss)	[1]			(4.6)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				0.1	0.1
Defined Benefit Plan, Net Periodic Benefit Cost				(10.8)	$ (6)
Employer contributions				10.8
Funded status of plan				$ 102.7
Expected return on plan assets				8.14%	8.15%
Settlement loss				$ 0	$ 0
Predecessor | Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities				8.3
Unrecognized Pension Benefit And Other Postretirement Benefit Costs
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets			$ 127.1
Unrecognized Pension Benefit And Other Postretirement Benefit Costs | Predecessor
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets				$ 120.9
[1]	The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.

Pension And Other Postretirem84

Pension And Other Postretirement Benefits (Schedule Of Portfolio Asset Mix) (Details)	12 Months Ended
	Dec. 31, 2015
Domestic Equities [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	25.00%
Equities, Maximum	45.00%
Domestic Equities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	35.00%
Equities, Maximum	55.00%
International Equities [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	15.00%
Equities, Maximum	25.00%
International Equities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	15.00%
Equities, Maximum	25.00%
Fixed Income [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	23.00%
Equities, Maximum	37.00%
Fixed Income [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	20.00%
Equities, Maximum	50.00%
Real Estate/Private Equity/Hedge Funds [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	0.00%
Equities, Maximum	15.00%
Real Estate/Private Equity/Hedge Funds [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	0.00%
Equities, Maximum	0.00%
Short-Term Investments [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	0.00%
Equities, Maximum	10.00%
Short-Term Investments [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Equities, Minimum	0.00%
Equities, Maximum	10.00%

Pension And Other Postretirem85

Pension And Other Postretirement Benefits (Schedule Of Pension Plan And Postretirement Plan Asset Mix) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	$ 508.4	$ 516.4
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	100.00%	100.00%
Fair value of asset	$ 294.3	$ 304.8
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	100.00%	100.00%
Fair value of asset	$ 213.9	$ 211.6
Domestic Equities [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	39.40%	41.10%
Fair value of asset	$ 115.9	$ 125.2
Domestic Equities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	44.60%	47.20%
Fair value of asset	$ 95.3	$ 99.9
International Equities [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	17.50%	18.10%
Fair value of asset	$ 51.4	$ 55
International Equities [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	18.70%	18.40%
Fair value of asset	$ 40.1	$ 38.9
Fixed Income [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	34.40%	34.40%
Fair value of asset	$ 101.5	$ 105
Fixed Income [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	33.60%	34.10%
Fair value of asset	$ 71.8	$ 72.2
Real Estate/Private Equity/Hedge Funds [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset		5.00%
Fair value of asset		$ 15.4
Real Estate/Private Equity/Hedge Funds [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset		0.00%
Fair value of asset		$ 0
Cash/Other [Member] | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	8.70%	1.40%
Fair value of asset	$ 25.5	$ 4.2
Cash/Other [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Percentage of total asset	3.10%	0.30%
Fair value of asset	$ 6.7	$ 0.6

Pension And Other Postretirem86

Pension And Other Postretirement Benefits (Schedule Of Fair Value Of Pension Plan Assets) (Details) - USD ($) $ in Millions		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		$ 508.4		$ 516.4
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		200.3		230.7
Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		307.9		269.8
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		15.3		$ 16.4
Due To Brokers Net [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0.3	[1]	0.1	[2]
Accrued Investment Income Dividends [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0.5		0.1
Receivables/Payables [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0.6
Fixed Income Securities [Member] | Other Fixed Income [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0.1		0
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		7.3		7.6
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		4.6		5
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		1		$ 1.2
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		294.3		304.8
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		294.3		304.2
Pension Plan | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		6.2		33.4
Pension Plan | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		288.1		255.5
Pension Plan | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Fair Value Of Plan Assets Before Pending Items		0		15.3
Pension Plan | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0.8		2.2
Pension Plan | Cash [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0.8		2.2
Pension Plan | Cash [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Cash [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		51.4		55
Pension Plan | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		101.5		105
Pension Plan | Equity Securities [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		5.4		17.6
Pension Plan | Equity Securities [Member] | International Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		5.4		17.5
Pension Plan | Equity Securities [Member] | International Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0.1
Pension Plan | Equity Securities [Member] | International Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Fixed Income Securities [Member] | Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		7.1		15.5
Pension Plan | Fixed Income Securities [Member] | Government [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		13.7
Pension Plan | Fixed Income Securities [Member] | Government [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		7.1		1.8
Pension Plan | Fixed Income Securities [Member] | Government [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Fixed Income Securities [Member] | Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		10.8		33.6
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		10.8		33.6
Pension Plan | Fixed Income Securities [Member] | Corporate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Fixed Income Securities [Member] | Mortgages/Asset Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0.4
Pension Plan | Fixed Income Securities [Member] | Mortgages/Asset Backed Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Fixed Income Securities [Member] | Mortgages/Asset Backed Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0.4
Pension Plan | Fixed Income Securities [Member] | Mortgages/Asset Backed Securities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Fixed Income Securities [Member] | Other Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0.1
Pension Plan | Fixed Income Securities [Member] | Other Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Fixed Income Securities [Member] | Other Fixed Income [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Fixed Income Securities [Member] | Other Fixed Income [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0.1
Pension Plan | Commingled Funds [Member] | U.S. Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		115.9		125.2
Pension Plan | Commingled Funds [Member] | U.S. Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | U.S. Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		115.9		125.2
Pension Plan | Commingled Funds [Member] | U.S. Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		45.7		36.6
Pension Plan | Commingled Funds [Member] | International Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | International Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		45.7		36.6
Pension Plan | Commingled Funds [Member] | International Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | Short-Term Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		25.5		4.3
Pension Plan | Commingled Funds [Member] | Short-Term Money Markets [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | Short-Term Money Markets [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		25.5		4.3
Pension Plan | Commingled Funds [Member] | Short-Term Money Markets [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		83.1		53.5
Pension Plan | Commingled Funds [Member] | Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Commingled Funds [Member] | Fixed Income [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		83.1		53.5
Pension Plan | Commingled Funds [Member] | Fixed Income [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[3]			7.3
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[3]			0
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[3]			0
Pension Plan | Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[3]			7.3
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[4]			4.6
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[4]			0
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[4]			0
Pension Plan | Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset	[4]			4.6
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				1
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				1
Pension Plan | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				2.3
Pension Plan | Real Estate [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Real Estate [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				0
Pension Plan | Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset				2.3
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		213.9		211.6
Other Postretirement Benefits | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		194.1		197.3
Other Postretirement Benefits | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		19.8		14.3
Other Postretirement Benefits | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		40.1		38.9
Other Postretirement Benefits | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		71.8		72.2
Other Postretirement Benefits | Commingled Funds [Member] | U.S. Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		13		13.6
Other Postretirement Benefits | Commingled Funds [Member] | U.S. Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Commingled Funds [Member] | U.S. Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		13		13.6
Other Postretirement Benefits | Commingled Funds [Member] | U.S. Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Commingled Funds [Member] | Short-Term Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		6.8		0.7
Other Postretirement Benefits | Commingled Funds [Member] | Short-Term Money Markets [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Commingled Funds [Member] | Short-Term Money Markets [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		6.8		0.7
Other Postretirement Benefits | Commingled Funds [Member] | Short-Term Money Markets [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | U.S. Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		82.3		86.4
Other Postretirement Benefits | Mutual Funds [Member] | U.S. Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		82.3		86.4
Other Postretirement Benefits | Mutual Funds [Member] | U.S. Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | U.S. Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		40.1		38.9
Other Postretirement Benefits | Mutual Funds [Member] | International Equities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		40.1		38.9
Other Postretirement Benefits | Mutual Funds [Member] | International Equities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | International Equities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		71.7		72
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		71.7		72
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		0		0
Other Postretirement Benefits | Mutual Funds [Member] | Fixed Income [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of asset		$ 0		$ 0
[1]	This class represents pending trades with brokers.
[2]	This class represents pending trades with brokers.
[3]	This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily in the United States.
[4]	This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

Pension And Other Postretirem87

Pension And Other Postretirement Benefits (Schedule Of Changes In The Fair Value Of The Plan Level Three Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		$ 516.4
Fair value of plan assets at end of year		508.4	$ 516.4
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		15.3	16.4
Total gains or losses (unrealized / realized)		0	0.5
Purchases		0	0.5
(Sales)		0	(2.1)
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(15.3)
Fair value of plan assets at end of year		0	15.3
Real Estate [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		2.3	2.6
Total gains or losses (unrealized / realized)		0	0.3
Purchases		0	0
(Sales)		0	(0.6)
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(2.3)
Fair value of plan assets at end of year		0	2.3
Private Equity Limited Partnerships [Member] | U.S. Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		7.3	7.6
Total gains or losses (unrealized / realized)		0	0.3
Purchases		0	0.3
(Sales)		0	(0.9)
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(7.3)
Fair value of plan assets at end of year		0	7.3
Private Equity Limited Partnerships [Member] | International Multi-Strategy [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		4.6	5
Total gains or losses (unrealized / realized)		0	(0.1)
Purchases		0	0.1
(Sales)		0	(0.4)
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(4.6)
Fair value of plan assets at end of year		0	4.6
Private Equity Limited Partnerships [Member] | Distressed Opportunities [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		1	1.2
Total gains or losses (unrealized / realized)		0	0
Purchases		0	0
(Sales)		0	(0.2)
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(1)
Fair value of plan assets at end of year		0	1
Fixed Income Securities [Member] | Other Fixed Income [Member] | Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		0.1	0
Total gains or losses (unrealized / realized)		0	0
Purchases		0	0.1
(Sales)		0	0
Transfers into/(out of) level 3		0	0
Defined Benefit Plan, Separation Allocation	[1]	(0.1)
Fair value of plan assets at end of year		$ 0	$ 0.1
[1]	Level 3 assets were not contributed to the Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation.

Pension And Other Postretirem88

Pension And Other Postretirement Benefits (Schedule Of Reconciliation Of The Plans Funded Status And Amounts Reflected) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year		$ 516.4
Fair value of plan assets at end of year		508.4	$ 516.4
Noncurrent assets		120.5
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]	345.2
Service cost	[1]	5.3
Interest cost	[1]	12.5
Plan participants' contributions	[1]	0
Actuarial loss (gain)	[1]	(7.3)
Benefits paid	[1]	(23.5)
Estimated benefits paid by incurred subsidy	[1]	0
Defined Benefit Plans, Contributed/Noncontributed Projected Benefit Obligation	[1],[2]	(4.6)
Projected benefit obligation at end of year	[1]	327.6	345.2
Fair value of plan assets at beginning of year			304.7
Fair value of plan assets at beginning of year		304.8
Actual return on plan assets		0.6
Employer contributions		16.5
Defined Benefit Plans, Contributed And Noncontributed Plan Assets	[2]	(4)
Fair value of plan assets at end of year		294.3	304.8
Funded Status at end of year		(33.3)	(40.5)
Noncurrent assets		0
Current liabilities		(0.1)
Noncurrent liabilities		(33.2)
Net amount recognized at end of year	[3]	(33.3)
Unrecognized prior service cost	[4]	(3)
Unrecognized actuarial loss	[4]	130.3
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[4]	127.3
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]	108.9
Service cost	[1]	1
Interest cost	[1]	4
Plan participants' contributions	[1]	1.6
Actuarial loss (gain)	[1]	(11.6)
Benefits paid	[1]	(7.5)
Estimated benefits paid by incurred subsidy	[1]	0.2
Defined Benefit Plans, Contributed/Noncontributed Projected Benefit Obligation	[1],[2]	(3.2)
Projected benefit obligation at end of year	[1]	93.4	108.9
Fair value of plan assets at beginning of year		211.6
Actual return on plan assets		(2)
Employer contributions		11.3
Defined Benefit Plans, Contributed And Noncontributed Plan Assets	[2]	(1.1)
Fair value of plan assets at end of year		213.9	211.6
Funded Status at end of year		120.5
Noncurrent assets		120.5
Current liabilities		0
Noncurrent liabilities		0
Net amount recognized at end of year	[3]	120.5
Unrecognized prior service cost	[4]	0.1
Unrecognized actuarial loss	[4]	(0.4)
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[4]	(0.3)
Predecessor
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets			102.7
Predecessor | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]	345.2	327.1
Service cost			4.8	[1]	$ 4.8
Interest cost			13.7	[1]	12.6
Plan participants' contributions	[1]		0
Actuarial loss (gain)	[1]		20
Benefits paid	[1]		(20.4)
Estimated benefits paid by incurred subsidy	[1]		0
Defined Benefit Plans, Contributed/Noncontributed Projected Benefit Obligation	[1],[2]		0
Projected benefit obligation at end of year	[1]		345.2		327.1
Fair value of plan assets at beginning of year		304.7	299.1
Actual return on plan assets			19.3
Employer contributions			6.7
Defined Benefit Plans, Contributed And Noncontributed Plan Assets	[2]		0
Fair value of plan assets at end of year			304.7		299.1
Funded Status at end of year			(40.5)
Noncurrent assets			0
Current liabilities			0
Noncurrent liabilities			(40.5)
Net amount recognized at end of year	[3]		(40.5)
Unrecognized prior service cost	[4]		(4)
Unrecognized actuarial loss	[4]		124.5
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[4]		120.5
Predecessor | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year	[1]	108.9	105.5
Service cost			1.1	[1]	1.5
Interest cost			4.6	[1]	4.9
Plan participants' contributions	[1]		1.9
Actuarial loss (gain)	[1]		4.6
Benefits paid	[1]		(9.1)
Estimated benefits paid by incurred subsidy	[1]		0.3
Defined Benefit Plans, Contributed/Noncontributed Projected Benefit Obligation	[1],[2]		0
Projected benefit obligation at end of year	[1]		108.9		105.5
Fair value of plan assets at beginning of year		$ 211.6	198.8
Actual return on plan assets			9.2
Employer contributions			10.8
Defined Benefit Plans, Contributed And Noncontributed Plan Assets	[2]		0
Fair value of plan assets at end of year			211.6		$ 198.8
Funded Status at end of year			102.7
Noncurrent assets			109.8
Current liabilities			0
Noncurrent liabilities			(7.1)
Net amount recognized at end of year	[3]		102.7
Unrecognized prior service cost	[4]		0.1
Unrecognized actuarial loss	[4]		(8.3)
Defined Benefit Plan Amounts Recognized In Other Comprehensive Income Or Regulatory Asset Or Liability	[4]		$ (8.2)
[1]	The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.
[2]	Reflects the removal of amounts related to Crossroads Pipeline Company and CPGSC, which 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]	The Partnership recognizes in its Consolidated and Combined Balance Sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
[4]	The Partnership determined that the future recovery of pension and other postretirement benefits costs is probable. The Partnership recorded regulatory assets and liabilities of $127.1 million and $0.6 million, respectively, as of December 31, 2015, and $120.9 million and $8.3 million, respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss.

Pension And Other Postretirem89

Pension And Other Postretirement Benefits (Schedule Of Significant Actuarial Assumptions In Determining Funded Status Plan) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.05%
Rate of Compensation Increases	4.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.28%
Trend for Next Year	8.38%
Ultimate Trend	4.50%
Year Ultimate Trend Reached	2,022
Predecessor | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		3.64%
Rate of Compensation Increases		4.00%
Predecessor | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		3.95%
Trend for Next Year		6.90%
Ultimate Trend		4.50%
Year Ultimate Trend Reached		2,021

Pension And Other Postretirem90

Pension And Other Postretirement Benefits (Schedule Of One-Percentage-Point Change In Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest components of net periodic cost, 1% point increase	$ 0.1
Effect on service and interest components of net periodic cost, 1% point decrease	(0.1)
Effect on accumulated postretirement benefit obligation, 1% point increase	2.5
Effect on accumulated postretirement benefit obligation, 1% point decrease	$ (2.3)

Pension And Other Postretirem91

Pension And Other Postretirement Benefits (Schedule Of Expected Payments To Participants In Pension Plan) (Details) $ in Millions	Dec. 31, 2015USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 27.2
2,017	27.1
2,018	27.9
2,019	28
2,020	30
2021-2025	145.8
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	6.2
2,017	6.2
2,018	6.3
2,019	6.4
2,020	6.4
2021-2025	31.4
Postretirement Health Coverage
Defined Benefit Plan Disclosure [Line Items]
2,016	0.3
2,017	0.3
2,018	0.3
2,019	0.3
2,020	0.3
2021-2025	$ 1.2

Pension And Other Postretirem92

Pension And Other Postretirement Benefits (Components Of The Plans' Net Periodic Benefits Cost) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	$ 5.3
Interest cost	[1]	12.5
Expected return on assets		(23.6)
Amortization of prior service cost		(0.9)
Recognized actuarial loss		8.2
Net Periodic Benefit Costs		1.5
Settlement loss		0
Total Net Periodic Benefits Cost		1.5
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	[1]	1
Interest cost	[1]	4
Expected return on assets		(17.4)
Amortization of prior service cost		0.1
Recognized actuarial loss		(0.2)
Net Periodic Benefit Costs		(12.5)
Settlement loss		0
Total Net Periodic Benefits Cost		$ (12.5)
Predecessor | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost			$ 4.8	[1]	$ 4.8
Interest cost			13.7	[1]	12.6
Expected return on assets			(23.8)		(22)
Amortization of prior service cost			(1)		(0.9)
Recognized actuarial loss			6.6		10.6
Net Periodic Benefit Costs			0.3		5.1
Settlement loss			0		12.4
Total Net Periodic Benefits Cost			0.3		17.5
Predecessor | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost			1.1	[1]	1.5
Interest cost			4.6	[1]	4.9
Expected return on assets			(16.5)		(13.5)
Amortization of prior service cost			0.1		0.1
Recognized actuarial loss			(0.1)		1
Net Periodic Benefit Costs			(10.8)		(6)
Settlement loss			0		0
Total Net Periodic Benefits Cost			$ (10.8)		$ (6)
[1]	The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.

Pension And Other Postretirem93

Pension And Other Postretirement Benefits (Schedule Of Key Assumptions That Were Used To Calculate The Net Periodic Benefits Cost) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.84%
Expected Long-Term Rate of Return on Plan Assets	8.20%
Rate of Compensation Increases	4.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.09%
Expected Long-Term Rate of Return on Plan Assets	8.06%
Predecessor | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		4.34%	3.36%
Expected Long-Term Rate of Return on Plan Assets		8.30%	8.30%
Rate of Compensation Increases		4.00%	4.00%
Predecessor | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		4.74%	3.92%
Expected Long-Term Rate of Return on Plan Assets		8.14%	8.15%

Pension And Other Postretirem94

Pension And Other Postretirement Benefits (Schedule Of Changes In Plan Assets And Projected Benefit Obligations Recognized In Other Comprehensive Income) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan
Net actuarial (gain)/loss	[1]	$ (7.3)
Amortization of prior service cost		0.9
Less: amortization of net actuarial (gain) loss		8.2
Other Postretirement Benefits
Net actuarial (gain)/loss	[1]	(11.6)
Amortization of prior service cost		(0.1)
Less: amortization of net actuarial (gain) loss		(0.2)
Predecessor | Pension Plan
Net actuarial (gain)/loss	[1]		$ 20
Amortization of prior service cost			1	$ 0.9
Less: amortization of net actuarial (gain) loss			6.6	10.6
Predecessor | Other Postretirement Benefits
Net actuarial (gain)/loss	[1]		4.6
Amortization of prior service cost			(0.1)	(0.1)
Less: amortization of net actuarial (gain) loss			(0.1)	$ 1
Regulatory Assets and Liabilities [Member] | Pension Plan
Net actuarial (gain)/loss		14.1
Amortization of prior service cost		(0.9)
Less: amortization of net actuarial (gain) loss		(8.2)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability		6.8
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability		8.3
Regulatory Assets and Liabilities [Member] | Other Postretirement Benefits
Net actuarial (gain)/loss		7.8
Amortization of prior service cost		0.1
Less: amortization of net actuarial (gain) loss		0.2
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability		7.9
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability		$ (4.6)
Regulatory Assets and Liabilities [Member] | Predecessor | Pension Plan
Net actuarial (gain)/loss			24.4
Amortization of prior service cost			(1)
Less: amortization of net actuarial (gain) loss			(6.6)
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability			18.8
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability			19.1
Regulatory Assets and Liabilities [Member] | Predecessor | Other Postretirement Benefits
Net actuarial (gain)/loss			11.7
Amortization of prior service cost			0
Less: amortization of net actuarial (gain) loss			0
Total Recognized in Other Comprehensive Income or Regulatory Asset or Liability			11.7
Amount Recognized in Net Periodic Benefits Cost and Other Comprehensive Income or Regulatory Asset or Liability			$ 0.9
[1]	The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.

Fair Value (Carrying Amount And

Fair Value (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Current portion of long-term debt-affiliated	$ 0
Current Portion of Long Term Debt-affiliated, Fair Value	0
Long-term debt-affiliated	630.9
Long-term debt-affiliated, Fair Value	$ 630.9
Predecessor
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Current portion of long-term debt-affiliated		$ 115.9
Current Portion of Long Term Debt-affiliated, Fair Value		120
Long-term debt-affiliated		1,472.8
Long-term debt-affiliated, Fair Value		$ 1,550.4

Other Commitments And Conting96

Other Commitments And Contingencies (Narrative) (Details) $ in Millions	Oct. 01, 2015	Aug. 18, 2015	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 05, 2014USD ($)
Other Commitments And Contingencies [Line Items]
Guarantees			$ 2,768.1
Line of Credit Facility, Maximum Borrowing Capacity			2,600
Ozone Level Maximum	70 ppb
Percentage Reduction in Methane Emissions		95.00%
Hours of Operation		26,000
Operating lease payments			18.5	$ 14.9	$ 13.4
Replacement Years		3 years
Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Commercial Paper			0
Line of Credit Facility Used For Credit Support for Subsidiaries			750
Line of Credit Facility Used For Corporate Purposes			750
Guarantee of Indebtedness of Others
Other Commitments And Contingencies [Line Items]
Guarantees			2,750
Letters Of Credit
Other Commitments And Contingencies [Line Items]
Guarantees			18.1
Revolving Credit Facility
Other Commitments And Contingencies [Line Items]
Credit facilities borrowings			15	$ 0
Revolving Credit Facility | Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Credit facilities borrowings			0
Letters Of Credit
Other Commitments And Contingencies [Line Items]
Letters of Credit Outstanding, Amount			0
Letters Of Credit | Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Letters of Credit Outstanding, Amount			18.1
Commercial Paper | Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,000
Revolving Credit Facility
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			500			$ 1,500
Revolving Credit Facility | Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,500
Letters Of Credit
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			50
Letters Of Credit | Columbia Pipeline Group
Other Commitments And Contingencies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 250

Other Commitments And Conting97

Other Commitments And Contingencies (Existence And Expiration Of Commercial Commitments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Other Commitments And Contingencies [Line Items]
2,016	$ 18.1
2,017	0
2,018	500
2,019	0
2,020	750
After	1,500
Total	2,768.1
Guarantee of Indebtedness of Others
Other Commitments And Contingencies [Line Items]
2,016	0
2,017	0
2,018	500
2,019	0
2,020	750
After	1,500
Total	2,750
Letters Of Credit
Other Commitments And Contingencies [Line Items]
2,016	18.1
2,017	0
2,018	0
2,019	0
2,020	0
After	0
Total	$ 18.1

Other Commitments And Conting98

Other Commitments And Contingencies (Future Minimum Lease Payments Required Under Operating And Capital Leases) (Details) $ in Millions	Dec. 31, 2015USD ($)	[1]
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 4.5
2,017	5.9
2,018	5.5
2,019	4.8
2,020	4.7
After	21.2
Total future minimum payments	$ 46.6
[1]	Operating lease expense includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.

Other Commitments And Conting99

Other Commitments And Contingencies (Estimated Aggregate Amounts Of Minimum Fixed Payments On Purchase And Service Obligations) (Details) - Pipeline Service Agreements [Member] $ in Millions	Dec. 31, 2015USD ($)
Other Commitments And Contingencies [Line Items]
2,016	$ 51.5
2,017	49.5
2,018	42
2,019	25.4
2,020	24.2
After	66.8
Total future minimum payments	$ 259.4

Accumulated Other Comprehens100

Accumulated Other Comprehensive Loss (Narrative) (Details) $ in Millions	Aug. 31, 2010USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2008USD ($)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number Of Notes Tranches Through Private Placement Issuance		2
Millennium Pipeline
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of interest rate swap agreements				3
Notional amount of interest rate swap agreements				$ 420
Number of counterparties entered into interest rate swap agreement				7
Refinancing of long-term debt	$ 725
Debt Instrument, Maturity Date		Jun. 1, 2025
Other Comprehensive Income Unrecognized Gain Loss On Derivatives Arising During Period Net Of Tax		$ 25	$ 16.6
Unrealized loss, amortization period		15 years
Notes Due 2027 [Member] | Millennium Pipeline
Accumulated Other Comprehensive Income (Loss) [Line Items]
Refinancing of long-term debt	$ 375
Debt Instrument, Interest Rate, Stated Percentage	5.33%
Debt Instrument, Maturity Date	Jun. 30, 2027
Notes Due 2032 | Millennium Pipeline
Accumulated Other Comprehensive Income (Loss) [Line Items]
Refinancing of long-term debt	$ 350
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt Instrument, Maturity Date	Jun. 30, 2032

Accumulated Other Comprehens101

Accumulated Other Comprehensive Loss (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
		Feb. 11, 2015	Dec. 31, 2015	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]			$ (0.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1],[2]			1.6
Total comprehensive income		$ 0.1	$ 1.2	1.3	[1]
Partners Capital Predecessor Net Liabilities Not Assumed By Subsidiary		1,222.2
Ending Balance	[1]		(4)	(4)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]			0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1],[2]			1.5
Total comprehensive income	[1]			1.5
Partners Capital Predecessor Net Liabilities Not Assumed By Subsidiary	[1],[3]			(10.2)
Ending Balance	[1]		(3.9)	(3.9)
Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]			(0.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1],[2]			0.1
Total comprehensive income	[1]			(0.2)
Partners Capital Predecessor Net Liabilities Not Assumed By Subsidiary	[1],[3]			(0.1)
Ending Balance	[1]		(0.1)	(0.1)
Gains and Losses on Cash Flow Hedges Attributable to Noncontrolling Interest
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total comprehensive income	[1]			(21.4)
Pension and OPEB Items Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total comprehensive income	[1]			(0.3)
AOCI Attributable to Noncontrolling Interest
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total comprehensive income	[1]			(21.7)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total comprehensive income		0.1	$ 0.2
Partners Capital Predecessor Net Liabilities Not Assumed By Subsidiary		(10.3)		(10.3)	[1],[3]
Predecessor
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(16.7)		(16.7)		$ (17.7)	$ (18.8)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]					0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]					1	1.1
Total comprehensive income	[1]					1	1.1
Ending Balance	[1]					(16.7)	(17.7)
Predecessor | Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	(16.6)		(16.6)		(17.6)	(18.7)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]					0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]					1	1.1
Total comprehensive income	[1]					1	1.1
Ending Balance	[1]					(16.6)	(17.6)
Predecessor | Pension and OPEB Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ (0.1)		$ (0.1)		(0.1)	(0.1)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	[1]					0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	[1]					0	0
Total comprehensive income	[1]					0	0
Ending Balance	[1]					$ (0.1)	$ (0.1)
[1]	All amounts prior to the IPO are net of tax. Amounts in parentheses indicate debits.
[2]	Includes amounts allocated to noncontrolling interest.
[3]	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.

Other, Net (Schedule Of Other N

Other, Net (Schedule Of Other Net) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Other, Net [Line Items]
AFUDC Equity		$ 28.3
Miscellaneous	[1]	3.7
Total Other, net		$ 32
Predecessor
Schedule Of Other, Net [Line Items]
AFUDC Equity			$ 11	$ 6.8
Miscellaneous	[1]		(2.2)	10.8
Total Other, net			$ 8.8	$ 17.6
[1]	Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

Segments Of Business (Narrative

Segments Of Business (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Number of Reportable Segments	1

Supplemental Cash Flow Infor104

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow [Line Items]
Capital expenditures included in current liabilities	[1]	$ 122.7
Cash paid for interest, net of interest capitalized amounts		40.3
Cash paid for income taxes		$ 0.2
Predecessor
Supplemental Cash Flow [Line Items]
Capital expenditures included in current liabilities	[1]		$ 78.5	$ 53.1
Cash paid for interest, net of interest capitalized amounts			53.6	39.5
Cash paid for income taxes			$ 21.5	$ 10.2
[1]	Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated and Combined Balance Sheets.

Concentration of Credit Risk (N

Concentration of Credit Risk (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Concentration Risk, Benchmark Description	greater than 10% of total operating revenues

Concentration of Credit Risk (S

Concentration of Credit Risk (Schedule of Concentration of Credit Risk) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Revenues		$ 1,331.8
Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues	[1]	$ 167.3
Concentration Risk, Percentage	[1]	12.60%
Predecessor
Concentration Risk [Line Items]
Revenues			$ 1,346.9	$ 1,179.4
Predecessor | Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues	[1]		$ 168.5	$ 167.5
Concentration Risk, Percentage	[1]		12.50%	14.20%
[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 we receive from Columbia Gas of Ohio in any given period.

Quarterly Financial Data (Un107

Quarterly Financial Data (Unaudited) (Schedule Of Quarterly Financial Data) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended								11 Months Ended	12 Months Ended
	Feb. 11, 2015	Mar. 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Line Items]
Operating Revenues			$ 357	$ 320	$ 315.6	$ 339.2	$ 340.4	$ 317.6	$ 343.4	$ 345.5
Operating Income			136.3	142.8	109.2	162	133.2	93.8	103.2	158.5		$ 550.3
Net Income			146.6	144.6	107.8	$ 131.2	$ 64.4	$ 53.2	$ 59	$ 92.5			$ 269.1	$ 266.9
Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 42.7		0	0	0						$ 487.5	530.2
Net income attributable to noncontrolling interest in Columbia OpCo subsequent to IPO		$ 75.2	124.2	122.6	91.5							413.5
Net income attributable to limited partners subsequent to the IPO		$ 13.3	$ 22.4	$ 22	$ 16.3						$ 74	$ 74
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax												$ 0.74
Common Units
Quarterly Financial Data [Line Items]
Net income attributable to limited partners subsequent to the IPO												$ 39.6
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax			$ 0.22	$ 0.22	$ 0.17	$ 0.13						$ 0.74
Subordinated Units
Quarterly Financial Data [Line Items]
Net income attributable to limited partners subsequent to the IPO												$ 33.8
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax			$ 0.22	$ 0.22	$ 0.16	$ 0.13						$ 0.72

Subsequent Event (Narrative) (D

Subsequent Event (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 16, 2016	Jan. 29, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	[1]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit			$ 0.1800	$ 0.1725	$ 0.1675	$ 0.0912
Distribution Made to Limited Partner, Distribution Date			Feb. 19, 2016	Nov. 20, 2015	Aug. 20, 2015	May 20, 2015
Distribution Made to Limited Partner, Date of Record			Feb. 11, 2016	Nov. 13, 2015	Aug. 13, 2015	May 13, 2015
Distribution Made to Limited Partner, Cash Distributions Paid			$ 18.1	$ 17.4	$ 16.9	$ 9.2
Subsequent Event
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.1800
Distribution Made to Limited Partner, Cash Distributions Declared		$ 18.1
Distribution Made to Limited Partner, Distribution Date		Feb. 19, 2016
Distribution Made to Limited Partner, Date of Record		Feb. 11, 2016
Distribution Made to Limited Partner, Cash Distributions Paid	$ 129.2
Columbia Energy Group | Subsequent Event
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	108.9
Columbia Pipeline Partners LP | Subsequent Event
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 20.3
[1]	The quarterly distribution for three months ended March 31, 2015 was prorated for the period beginning immediately after the closing of the IPO, February 11, 2015 through March 31, 2015.