EL Paso Pipeline Partners (EPB) 10-K 19 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 28, 2013	Jan. 31, 2014	Jan. 31, 2014
			Common units [Member]	General Partner [Member]
Entity Registrant Name	'El Paso Pipeline Partners, L.P.	'	'	'
Entity Central Index Key	'0001410838	'	'	'
Document Type	'10-K	'	'	'
Document Period End Date	31-Dec-13	'	'	'
Amendment Flag	'false	'	'	'
Document Fiscal Year Focus	'2013	'	'	'
Document Fiscal Period Focus	'FY	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'	'
Entity Voluntary Filers	'No	'	'	'
Entity Current Reporting Status	'Yes	'	'	'
Entity Filer Category	'Large Accelerated Filer	'	'	'
Entity Public Float	'	$5,558,190,957	'	'
Entity Common Stock, Shares Outstanding	'	'	217,831,642	4,445,455

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues	$1,505		$1,515		$1,531
Operating Costs and Expenses	'		'		'
Operations and maintenance	329		387		419
Depreciation and amortization	198		183		180
Taxes, other than income taxes	83		82		83
Total Operating Costs and Expenses	610		652		682
Operating Income	895		863		849
Other Income (Expense)	'		'		'
Earnings from equity investments	13		14		15
Interest expense, net	-300		-293		-267
Other, net	2		5		8
Total Other Income (Expense)	-285		-274		-244
Net Income	610		589		605
Net Income Attributable to Noncontrolling Interests	0		-10		-93
Net Income Attributable to El Paso Pipeline Partners, L.P.	610		579		512
Calculation of Limited Partners' Interest in Net Income Attributable to El Paso Pipeline Partners, L.P.:	'		'		'
Net Income Attributable to El Paso Pipeline Partners, L.P.	610		579		512
Less: Pre-acquisition Earnings Allocated to General Partner	0		-22		-40
Plus: Severance Costs Allocated to General Partner	1		34		0
Income Subject to 2% Allocation of General Partner Interest	611		591		472
Less: General Partner's Interest	-12		-12		-9
General Partner's Incentive Distribution	-195	[1]	-129	[1]	-62	[1]
Limited Partners' Interest in Net Income	$404		$450		$401
Limited Partnersb Net Income per Unit- Basic and Diluted	$1.86		$2.15		$2.03
Weighted Average Number of Units Used in Computation of Limited Partnersb Net Income per Unit- Basic and Diluted	217		209		197
Per Unit Cash Distribution Declared for the Period	$2.55		$2.25		$1.93
[1]	The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units.

CONSOLIDATED_STATEMENTS_OF_INC1

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Percentage of general partner interest	2.00%	2.00%	2.00%

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Net Income	$610	$589		$605
Other Comprehensive Income:	'	'		'
Change in fair value of derivatives utilized for hedging purposes	0	-1		-6
Reclassification of change in fair value of derivatives to net income	0	4		7
Reclassification of terminated hedge to net income	0	12	[1]	0
Adjustments to postretirement benefit plan liabilities	0	2		9
Total Other Comprehensive Income	0	17		10
Comprehensive Income	610	606		615
Comprehensive Income Attributable to Noncontrolling Interests	0	-10		-94
Comprehensive Income Attributable to El Paso Pipeline Partners, L.P.	$610	$596		$521
[1]	See Note 10 for further discussion.

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$78	$114
Accounts receivable, net	147	155
Inventories	34	34
Regulatory assets	26	46
Other current assets	19	6
Total current assets	304	355
Property, plant and equipment, net	5,879	5,931
Investments	87	72
Regulatory assets	120	147
Deferred charges and other assets	105	76
Total Assets	6,495	6,581
Current liabilities	'	'
Current portion of debt	77	93
Accounts payable	73	67
Accrued interest	51	53
Accrued taxes, other than income	37	31
Regulatory liabilities	17	17
Other current liabilities	22	20
Total current liabilities	277	281
Long-term liabilities and deferred credits	'	'
Long-term debt	4,171	4,246
Other long-term liabilities and deferred credits	108	67
Total Liabilities	4,556	4,594
Commitments and contingencies (Note 9)	'	'
Partners' capital	'	'
Common units (217,831,642 and 215,789,325 units issued and outstanding at December 31, 2013 and 2012)	4,197	4,253
General partner units (4,445,455 and 4,403,765 units issued and outstanding at December 31, 2013 and 2012)	-2,268	-2,276
Accumulated other comprehensive income	10	10
Total Partners' Capital	1,939	1,987
Total Liabilities and Partners' Capital	$6,495	$6,581

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Common Units, Issued	217,831,642	215,789,325
Common Units, Outstanding	217,831,642	215,789,325
General Partners' Units, Issued	4,445,455	4,403,765
General Partners' Units, Outstanding	4,445,455	4,403,765

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows From Operating Activities	'	'	'
Net Income	$610	$589	$605
Adjustments to reconcile net income to net cash from operating activities:	'	'	'
Depreciation and amortization	198	183	180
Earnings from equity investments	-13	-14	-15
Distributions from equity investment earnings	11	13	15
Non-cash severance costs	1	34	0
Other non-cash items	15	22	26
Changes in components of working capital:	'	'	'
Accounts receivable	7	-56	0
Regulatory assets	23	-10	5
Other current assets, including inventories	0	-2	5
Accounts payable	-4	-30	14
Accrued interest	-2	2	7
Accrued taxes, other than income	3	-8	-3
Regulatory liabilities	3	1	-17
Other current liabilities	-2	-23	2
Other long-term assets and liabilities	8	15	-6
Net Cash Provided by Operating Activities	858	716	818
Cash Flows From Investing Activities	'	'	'
Capital expenditures	-125	-109	-255
Contributions to equity investments	-13	0	0
Cash paid to acquire interests in CPG	0	-185	0
Proceeds from sale of assets	0	50	1
Other, net	-4	-5	-13
Net Cash Used in Investing Activities	-142	-249	-267
Cash Flows From Financing Activities	'	'	'
Issuance of debt	87	1,274	1,771
Payments of debt	-180	-1,050	-1,318
Net proceeds from issuance of common and general partner units	87	279	968
Cash distributions to unitholders and general partner	-746	-564	-422
Cash distributions to CPG's preferred interest	0	0	-14
Cash distributions by subsidiaries to El Paso	0	-28	-116
Cash contributions to subsidiaries from El Paso	0	2	34
Excess of cash paid for CPG interests over contributed book value	0	-180	0
Cash paid to acquire additional interests in CIG and SNG	0	-206	-1,412
Other	0	0	-1
Net Cash Used In Financing Activities	-752	-473	-510
Net (decrease) increase in Cash and Cash Equivalents	-36	-6	41
Cash and Cash Equivalents, beginning of period	114	120	79
Cash and Cash Equivalents, end of period	78	114	120
Non-cash Investing Activities	'	'	'
Increase (decrease) in property, plant and equipment accruals and contractor retainage	7	-4	-25
Supplemental Cash Flow Information	'	'	'
Cash paid during the period for interest (net of capitalized interest)	$283	$274	$274

CONSOLIDATED_STATEMENTS_OF_PAR

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (USD $)	Total	Limited partner common units [Member]		Limited partner subordinated units [Member]		General partner [Member]	Accumulated other comprehensive income/ (loss) [Member]	Total EPB Partners' Capital [Member]	Noncontrolling interests [Member]
In Millions, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2010	'	$2,686		$307		($1,525)	($15)	'	$981
Beginning Balance, Units at Dec. 31, 2010	180,783,441	149,440,452		27,727,411		3,615,578	'	'	'
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'		'		'	'	'	'
Net income	605	401		'		111	'	'	79
Conversion of subordinated units to common units	'	307		-307		'	'	'	'
Conversion of subordinated units to common units, Units	0	27,727,411	[1]	-27,727,411	[1]	0	'	'	'
Issuance of units, net of issuance costs	'	948		'		20	'	'	'
Issuance of units	'	28,530,887		'		582,244	'	'	'
Cash distributions to unitholders and general partner	-422	-365		'		-57	'	'	'
Cash distributions by subsidiaries to El Paso	'	'		'		-37	'	'	-79
Cash contributions to subsidiaries from El Paso	'	'		'		4	'	'	30
Cash paid to general partner to acquire interests in CIG, CPG and SNG	'	'		'		-1,412	'	'	'
Acquisition of additional interests in CIG and SNG	'	'		'		896	'	'	'
Third party preferred interest in CPG transferred to El Paso	'	'		'		145	'	'	'
Acquisition of additional interests in CIG and SNG	'	'		'		'	'	'	-896
Other comprehensive income	'	'		'		'	8	'	1
Ending Balance at Dec. 31, 2011	2,231	3,977		0		-1,855	-7	2,115	116
Ending Balance, Units at Dec. 31, 2011	209,896,572	205,698,750		0		4,197,822	'	209,896,572	'
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'		'		'	'	'	'
Net income	589	450		'		129	'	'	10
Issuance of units, net of issuance costs	'	272		'		7	'	'	'
Issuance of units	'	8,169,824		'		166,744	'	'	'
Cash distributions to unitholders and general partner	-564	-447		'		-117	'	'	'
Units issued to acquire interests in CIG and CPG	'	0		'		0	'	'	'
Units issued to acquire interests in CIG and CPG, Units	1,959,950	1,920,751		0		39,199	'	'	'
Cash distributions by subsidiaries to El Paso	'	'		'		-15	'	'	-13
Cash contributions to subsidiaries from El Paso	'	'		'		'	'	'	2
Cash paid to general partner to acquire interests in CIG, CPG and SNG	'	'		'		-571	'	'	'
Acquisition of additional interests in CIG and SNG	'	'		'		114	1	'	'
Non-cash contributions from general partner	'	'		'		34	'	'	'
Other	'	1		'		-2	'	'	'
Acquisition of additional interests in CIG and SNG	'	'		'		'	'	'	-115
Other comprehensive income	'	'		'		'	16	'	'
Ending Balance at Dec. 31, 2012	1,987	4,253		'		-2,276	10	1,987	0
Ending Balance, Units at Dec. 31, 2012	220,193,090	215,789,325		0		4,403,765	'	220,193,090	'
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'		'		'	'	'	'
Net income	610	404		'		206	'	'	'
Issuance of units, net of issuance costs	'	85		'		2	'	'	'
Issuance of units	'	2,042,317		'		41,690	'	'	'
Cash distributions to unitholders and general partner	-746	-545		'		-201	'	'	'
Non-cash contributions from general partner	'	'		'		1	'	'	'
Other comprehensive income	'	'		'		'	0	'	'
Ending Balance at Dec. 31, 2013	$1,939	$4,197		'		($2,268)	$10	$1,939	'
Ending Balance, Units at Dec. 31, 2013	222,277,097	217,831,642		0		4,445,455	'	222,277,097	'
[1]	All subordinated units were converted to common units on a one-for-one basis effective JanuaryB 3, 2011. See additional discussion below regarding subordinated units.

General

General	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
General	'
	General
	We are a Delaware MLP formed in 2007 to own and operate interstate natural gas transportation and terminaling facilities. We own WIC, SLNG, Elba Express, SNG, CIG, SLC and CPG. WIC and CIG are interstate pipeline systems serving the Rocky Mountain region. CPG has an interstate pipeline which serves the Rocky Mountain and Midwest regions. SLNG owns the Elba Island LNG storage and regasification terminal near Savannah, Georgia. Elba Express and SNG are interstate pipeline systems serving the southeastern region of the U.S. Our equity method investments include WYCO, which is owned 50% by CIG, Bear Creek, which is owned 50% by SNG, and ELC, which is owned 51% by SLC. ELC was formed in January 2013 to develop and own a natural gas liquefaction plant at SLNG's existing Elba Island LNG terminal. We are controlled by our general partner, El Paso Pipeline GP Company, L.L.C., an indirect wholly owned subsidiary of KMI.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Basis of Presentation
	We have prepared our accompanying consolidated financial statements under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB's Accounting Standards Codification, the single source of GAAP and referred to in this report as the Codification. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
	Additionally, our financial statements are consolidated into the consolidated financial statements of KMI. Also, except for the related party transactions described in Note 8, KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI's financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
	Principles of Consolidation
	We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity.  The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.
	Use of Estimates
	Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
	In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. Below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
	Cash Equivalents
	We consider short-term investments with an original maturity of less than three months to be cash equivalents.
	Accounts Receivable
	The amounts reported as “Accounts receivable, net” on our accompanying Consolidated Balance Sheets at December 31, 2013 and 2012 primarily consist of amounts due from third party payors (unrelated entities). For information on receivables due to us from related parties, see Note 8.
	We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. The allowance for doubtful accounts as of December 31, 2013 and 2012 and the bad debt expense for the years ended December 31, 2013, 2012 and 2011 were not significant.
	Inventories
	Our inventories, which consist of materials and supplies, are valued at the lower of cost or market value with cost determined using the average cost method.
	Natural Gas Imbalances
	Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system differs from the scheduled amount of gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of the applicable FERC tariff. Imbalances due from others are reported in the Consolidated Balance Sheets as "Other current assets." Imbalances owed to others are reported in the Consolidated Balance Sheets as "Other current liabilities." We classify all imbalances as current as we expect them to be settled within a year.
	Property, Plant and Equipment
	Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Our indirect construction costs primarily include an interest and equity return component (as more fully described below) and labor and related costs of departments associated with supporting construction activities. The indirect capitalized labor and related costs are based upon estimates of time spent supporting construction projects.
	We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals the salvage value. For certain general plant, the asset is depreciated to zero. We re-evaluate depreciation rates each time we redevelop our transportation and storage rates to file with the FERC for an increase or decrease in rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not recognize gains or losses unless we sell or retire an entire operating unit, as determined by the FERC. We generally include gains or losses on dispositions of operating units in "Operations and maintenance" expense in our Consolidated Statements of Income. In those instances where we receive recovery in rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. See Note 3 for information related to a regulatory asset we recorded associated with the sale of certain SNG assets.
	Included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheets if deemed probable of recovery through future rates charged to customers.
	We capitalize a carrying cost (AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to "Interest expense, net" on our Consolidated Statements of Income. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in "Other, net" on our Consolidated Statements of Income.
	Asset Retirement Obligations
	We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses.  We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired.  Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets.  The liabilities are eventually extinguished when the asset is taken out of service.
	We are required to operate and maintain our natural gas pipelines, storage systems and LNG facilities, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline system assets and LNG facility assets because these assets have indeterminate lives.
	We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. Our asset retirement obligations were not significant as of December 31, 2013 and 2012.
	Asset and Investment Divestitures/Impairments
	We evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on either (i) the long-lived asset's ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value.
	Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.
	We classify assets (or groups of assets) to be disposed of as held for sale when specific criteria have been met. The lower of the carrying value or the estimated fair value less the cost to sell those assets is considered to determine if recognition of an impairment is required.  We cease depreciation and amortization of the assets in the period they are considered held for sale.
	Equity Method of Accounting
	We account for investments, which we do not control but do have the ability to exercise significant influence, by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition costs, increased by our proportionate share of the investee's net income and by contributions made, and decreased by our proportionate share of the investee's net losses and by distributions received.
	Revenue Recognition
	Our revenues are primarily generated from natural gas transportation, storage and processing services as well as from LNG storage services and terminal operations and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation services and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Gas not used in operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes.
	We recognize revenue from gas not used in operations from our shippers when the FERC allows us to retain the volumes at the market prices required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We had no reserves for potential refunds as of December 31, 2013 and 2012.
	Environmental Matters
	We expense or capitalize, as appropriate, environmental expenditures that relate to current operations.  We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation.  We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.  We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.
	We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts.  We also routinely adjust our environmental liabilities to reflect changes in previous estimates.  In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims.  Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.  These revisions are reflected in our income in the period in which they are reasonably determinable.  For more information on our environmental disclosures, see Note 9.
	Legal
	We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such litigation based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.  For more information on our legal disclosures, see Note 9.
	Other Contingencies
	We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue an undiscounted liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
	Postretirement Benefits
	CIG and SNG, our consolidated subsidiaries, maintain a postretirement benefit plan covering certain of their former employees. The plan requires them to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. The net benefit cost of the plan is recorded in our Consolidated Statements of Income and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to CIG's and SNG's postretirement benefit plan, see Note 6.
	In accounting for CIG's and SNG's postretirement benefit plan, we record an asset or liability based on the difference between the fair value of the plan's assets and the plan's benefit obligation. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability or recorded as "Other comprehensive income" until those gains or losses are recognized on our Consolidated Statements of Income.
	Noncontrolling Interests
	Noncontrolling interests represent the outstanding ownership interests in our consolidated operating limited partnerships that are not owned by us. In our accompanying Consolidated Statements of Income, the noncontrolling interests in our net income are shown as an allocation of our consolidated net income and are presented separately as “Net income attributable to noncontrolling interests.” In our accompanying Consolidated Balance Sheets, noncontrolling interests represent the ownership interests in our net assets held by parties other than us and are presented separately as “Noncontrolling interests.” For the year ended December 31, 2013, we had no non-wholly owned consolidated subsidiaries.
	Limited Partners' Net Income per Unit
	We compute “Limited partners' net income per unit” by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period.
	Partners' Capital
	We allocate our net income to the capital accounts of our general partner and limited partner unitholders based on the terms of the partnership agreement. The agreement requires these allocations to be made based on the relative percentage of their ownership interests, adjusted for any replenishment of previously allocated aggregate net losses and/or special allocations, each as defined in our partnership agreement. As a result of the retrospective consolidation of CIG, SNG and CPG, earnings prior to the acquisitions of the incremental interests in these subsidiaries (pre-acquisition earnings) have been allocated solely to our general partner. See Note 3 for additional information related to the retrospective consolidation of subsidiaries to reflect the reorganization of entities under common control and the change in reporting entity.
	Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities on the terms and conditions determined by our general partner without the approval of our unitholders. Accordingly, all of our issued units are authorized and outstanding, and there are an unlimited number of units that are authorized beyond those currently issued.
	Regulated Operations
	Our interstate natural gas pipelines, storage operations and LNG receiving terminal are subject to the jurisdiction of the FERC and follow the FASB's accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement benefit plan costs, losses on reacquired debt, losses on the sale of certain long lived assets, taxes related to an equity return component on regulated capital projects in periods prior to our subsidiaries' change in legal structure to non-taxable entities, certain cost differences between gas retained and gas consumed in operations and other costs included in, or expected to be included in, future rates. See Note 11 for further discussion regarding our regulated operations.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2013
Acquisitions and Divestitures [Abstract]	'
Acquisitions and Divestitures	'
	Acquisitions and Divestitures
	2011 Acquisitions
	In March 2011, we acquired an additional 25% interest in SNG from El Paso for $667 million in cash. We financed the acquisition through (i) net proceeds of $467 million from our March 2011 public offering of common units and related issuance of general partner units to El Paso and (ii) $200 million borrowings under our revolving credit agreement. This transaction was for the acquisition of an additional interest in an already consolidated entity, thus was accounted for on a prospective basis.
	In June 2011, we acquired the remaining 15% interest in SNG and an additional 28% interest in CIG from El Paso for $745 million in cash. We financed the acquisition through (i) net proceeds of $501 million from our May 2011 public offering of common units and related issuance of general partner units to El Paso, including the underwriters’ June 2011 exercise of the overallotment option and (ii) $244 million borrowings under our revolving credit agreement. This transaction was for the acquisition of additional interests in already consolidated entities, thus was accounted for on a prospective basis.
	We have decreased our historical noncontrolling interests in SNG and CIG for both the March and June 2011 acquisitions by $896 million and reflected that amount as an increase to "General Partner’s Capital." We reflected El Paso’s interest in SNG and CIG as noncontrolling interest in our financial statements. El Paso’s interest in SNG was 40% from January 1, 2011 to March 13, 2011 and 15% until the June 29, 2011 acquisition of the remaining interest. Subsequent to the June 2011 acquisition, SNG became a wholly owned subsidiary of EPB. We reflected El Paso’s 42% interest in CIG as noncontrolling interest in our financial statements for the period from January 1, 2011 to June 29, 2011 and 14% until the May 24, 2012 acquisition of the remaining interest.
	2012 Acquisitions
	In May 2012, we acquired the remaining 14% interest in CIG and a 100% interest in CPG from El Paso for $635 million. The consideration paid to El Paso consisted of $571 million in cash and the issuance of common units. We financed the cash payment through (i) $570 million in borrowings under our credit agreement and (ii) $1 million from the issuance of general partner units. We recorded our interest in CPG at its historical cost of $185 million and the excess cash paid over contributed book value of $180 million as a decrease to general partner's capital. Also decreasing general partner's capital was $206 million of cash paid to acquire the remaining interest in CIG. Subsequent to the acquisition, we had the ability to control CPG's operating and financial decisions and policies and have consolidated CPG in our financial statements. We have retrospectively adjusted our historical financial statements in all periods presented to reflect the reorganization of entities under common control and the change in reporting entity. As a result of the retrospective consolidation, the pre-acquisition earnings of CPG have been allocated solely to our general partner. The retrospective consolidation of CPG increased net income attributable to El Paso Pipeline Partners, L.P. by $22 million and $40 million and for 2012 and 2011, respectively. The acquisition of the remaining interest in CIG was for an additional interest in an already consolidated entity; therefore, it was accounted for prospectively. We have decreased the remaining noncontrolling interest in CIG for the May 2012 acquisition by $115 million and reflected that amount as an increase to "General Partner's Capital" and "Accumulated other comprehensive income (loss)."
	For additional information related to the funding of our acquisitions with debt and equity issuances, see Notes 5 and 7, respectively.
	Divestitures
	SNG Assets
	In September 2011, SNG entered into an agreement to sell certain offshore and onshore assets (including pipeline, platforms and other related assets located in the Gulf of Mexico and Louisiana) for approximately $50 million. SNG deferred the estimated loss as a regulatory asset. On June 21, 2012, the FERC issued an order approving the sale, which occurred on November 1, 2012. The regulatory asset balance as of December 31, 2012 of $36 million represented the difference between the net book value and the $50 million sales price amortized by a fixed monthly rate pursuant to the settlement of SNG's rate case. As of December 31, 2013, the regulatory asset balance was $23 million. In accordance with the settlement of SNG's rate case, which was approved by the FERC on July 12, 2013, the recovery of the total regulatory asset will occur over a three-year period ending October 31, 2015.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Classes of Assets and Depreciation Rates
	As of December 31, 2013 and 2012, our property plant and equipment consisted of the following (in millions, except for %):
		Annual Depreciation Rates	December 31,
		(%)	2013			2012
	Transmission and storage facilities	0.9-10.0	$	7,886		$	7,779
	General plant	1.76-25.0	66			67
	Intangible plant	1.76-23.0	126			128
	Other		196			202
	Accumulated depreciation and amortization(a)		(2,472		)	(2,321		)
			5,802			5,855
	Land		24			24
	Construction work in progress		53			52
	Property, plant and equipment, net		$	5,879		$	5,931
	——————
	(a)	The composite weighted average depreciation rates for the years ended December 31, 2013, 2012 and 2011 were 2.29%, 2.18% and 2.19%, respectively.
	Capitalized Costs During Construction
	The allowance for debt interest amounts capitalized during the years ended December 31, 2013, 2012 and 2011 was $1 million, $1 million and $2 million, respectively. The allowance for equity amounts capitalized during each of the years ended December 31, 2013, 2012 and 2011 was $2 million, $3 million and $7 million, respectively.

Debt

Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	Debt
	We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our Consolidated Statements of Income. The following table summarizes the net carrying value of our outstanding debt (in millions):
		As of December 31,
		2013			2012
	EPPOC
	Senior Notes, 8.00%, due 2013	$	—		$	88
	Senior Notes, 4.10%, due 2015	375			375
	Senior Notes, 6.50%, due 2020	535			535
	Senior Notes, 5.00%, due 2021	500			500
	Senior Notes, 7.50%, due 2040	375			375
	Senior Notes, 4.70%, due 2042	475			475
	Revolving credit agreement, variable, due 2016(a)	—			—
	CIG
	Senior Notes, 5.95%, due 2015	35			35
	Senior Notes, 6.80%, due 2015	340			340
	Senior Debentures, 6.85%, due 2037	100			100
	SLNG
	Senior Notes, 9.50%, due 2014	71			71
	Senior Notes, 9.75%, due 2016	64			64
	SNG
	Notes, 5.90%, due 2017	500			500
	Notes, 4.40%, due 2021	300			300
	Notes, 7.35%, due 2031	153			153
	Notes, 8.00%, due 2032	258			258
	Total long-term debt	4,081			4,169
	Other financing obligations	175			178
	Total long-term debt and other financing obligations	4,256			4,347
	Less: Unamortized discount	8			8
	Current maturities	77			93
	Total long-term debt and other financing obligations, less current maturities	$	4,171		$	4,246
	——————
	(a)	LIBOR plus 1.75%.
	Credit Agreement
	In May 2011, EPPOC and WIC entered into an unsecured 5-year credit agreement with an initial aggregate borrowing capacity of $1.0 billion, expandable to $1.5 billion for certain expansion projects and acquisitions. EPPOC is a wholly owned subsidiary of EPB. In May 2012, we borrowed from our revolving credit agreement to fund the acquisition of CPG and the remaining interest in CIG (see Note 3). On May 24, 2012, Standard & Poor's raised our credit rating, triggering a pricing level change. Our interest rate for borrowings under our credit agreement has decreased from the LIBOR plus 2% to LIBOR plus 1.75% and the commitment fee paid for unutilized commitments decreased from 0.4% to 0.3% and these rates remained effective at December 31, 2013. At December 31, 2013, EPPOC's senior debt was rated investment grade by Fitch Ratings (BBB-) and Standard & Poor's (BBB-) and below investment grade by Moody’s Investor Services (Ba1). During 2013, we drew and repaid $87 million from our revolving credit agreement and as of December 31, 2013, we had no outstanding balance. Our remaining availability under this facility was $1.0 billion. Borrowings under the credit agreement are guaranteed by EPB.
	The credit agreement contains covenants and provisions that affect us, the borrowers and our other restricted subsidiaries, including, without limitation, customary covenants and provisions:
	•	prohibiting the borrowers from creating or incurring indebtedness (except for certain specified permitted indebtedness) if such incurrence would cause a breach of the leverage ratio described below;
	•	limiting our ability and that of the borrowers and our other restricted subsidiaries from creating or incurring certain liens on our respective properties (subject to enumerated exceptions);
	•	limiting our ability to make distributions and equity repurchases (which shall be permitted if no insolvency default or event of default exists); and
	•	prohibiting consolidations, mergers and asset transfers by us, the borrowers and our other restricted subsidiaries (subject to enumerated exceptions).
	The credit agreement requires that EPB and WIC maintain a consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA) as defined in the credit agreement as of the end of each quarter of less than 5.0 to 1.0 for any trailing four consecutive quarter period; and 5.5 to 1.0 for any such four quarter period during the three full fiscal quarters subsequent to the consummation of specified permitted acquisitions having a value greater than $25 million. We also have additional flexibility to our covenants for growth projects. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25% of actual consolidated EBITDA.
	The credit agreement contains certain customary events of default that affect us, the borrowers and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within 5 business days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, the borrowers or any of our other restricted subsidiaries; (iii) judgment defaults against us, our general partner, the borrowers or any of our other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso to directly or indirectly own a majority of the voting equity of our general partner and a failure by us to directly or indirectly own 100% of the equity of EPPOC. As of December 31, 2013 and 2012, we were in compliance with the credit agreement covenants.
	EPPOC Senior Notes
	EPPOC’s senior notes are guaranteed fully and unconditionally by its parent, EPB. EPPOC is a wholly owned subsidiary of EPB. EPB’s only operating asset is its investment in EPPOC, and EPPOC’s only operating assets are its investments in WIC, CIG, SLNG, Elba Express, SNG, ELC and CPG (collectively, the non-guarantor operating companies). EPB’s and EPPOC’s independent assets and operations, other than those related to these investments and EPPOC’s debt are less than 3% of the total assets and operations of EPB, and thus substantially all of the operations and assets exist within these non-guarantor operating companies. Furthermore, there are no significant restrictions on EPPOC’s or EPB’s ability to access the net assets or cash flows related to their controlling interests in the operating companies either through dividend or loan. The restrictive covenants under these debt obligations are no more restrictive than the restrictive covenants under our credit agreement. As of December 31, 2013 and 2012, EPPOC was in compliance with all of its debt related covenants.
	In November 2012, EPPOC issued $475 million of 4.7% senior notes due in 2042. The net proceeds of $469 million were used to reduce outstanding indebtedness under EPB’s revolving credit agreement and for general partnership purposes.
	In September 2013, EPPOC repaid $88 million of 8.00% senior notes.
	CIG Debt
	CIG is subject to a number of restrictions and covenants under its debt obligation. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. For the year ended December 31, 2013 and 2012, CIG was in compliance with its debt-related covenants.
	SLNG Debt
	The SLNG senior notes impose certain limitations on the ability of SLNG to, among other things, incur additional indebtedness, make certain restricted payments, enter into transactions with affiliates, and merge or consolidate with any other person, sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its assets. SLNG is required to comply with certain financial covenants, including a leverage ratio of no more than 5.0 to 1.0 and an interest coverage ratio of no less than 2.0 to 1.0.
	The SLNG senior notes are unsecured and are redeemable at SLNG’s option at 100% of the principal amount plus a specified make-whole premium. The SLNG notes are also subject to a change of control prepayment offer in the event of a ratings downgrade within a 120-day period from and including the date on which a change of control with respect to SLNG occurs (as defined in the note purchase agreement). If a sufficient number of the rating agencies downgrade the ratings of the SLNG notes below investment grade within the 120-day period from and including the date of any such change of control, then SLNG is required to offer to prepay the entire unpaid principal amount of the notes held by each holder at 101% of the principal amount of such SLNG notes (without any make-whole amount or other penalty), together with interest accrued thereon to the date for such prepayment. As of December 31, 2013 and 2012, SLNG was in compliance with its debt related covenants.
	SNG Debt
	Under its indentures, SNG is subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. As of December 31, 2013 and 2012, SNG was in compliance with debt-related covenants.
	Southern Natural Issuing Corporation (SNIC) is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.
	CPG Debt
	In May 2005, CPG entered into a $266 million nonrecourse project financing agreement with a maturity date of March 31, 2015. During 2012, we made principal and interests payments of $8 million. Additionally, in September 2012, we repaid the remaining borrowings of $172 million under the term loan and canceled a related $12 million letter of credit. See Note 10 for information related to the settlement of the interest rate swaps associated with this loan agreement.
	Other Financing Obligations
	In conjunction with the construction of Totem and High Plains, CIG’s joint venture partner in WYCO funded 50% of the construction costs. We reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and, upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, we transferred our title in the projects to WYCO and leased the assets back. Although we transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of our continuing involvement through our equity investment in WYCO. As such, the costs of the facilities remain on our balance sheets and the advanced payments received from our 50% joint venture partner were converted into a financing obligation due to WYCO.
	As of December 31, 2013, the principal amounts of the Totem and High Plains financing obligations were $75 million and $94 million, respectively, which will be paid in monthly installments through 2039, and extended for the term of related firm service agreements until 2060 and 2043, respectively. The effective interest rate on these obligations is 15.5%, payable on a monthly basis.
	Maturities of Debt
	The scheduled maturities of our outstanding debt as of December 31, 2013 are summarized as follows (in millions):
	Year		Commitment
	2014		$	77
	2015		756
2016		69
2017		505
2018		5
Thereafter		2,844
Total long-term debt and other financing obligations		$	4,256

Retirement_Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Retirement Benefits	'
	Retirement Benefits
	Pension and Retirement Savings Plans
	KMI maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including CIG’s and SNG’s former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, KMI contributes an amount equal to 5% of participants' eligible compensation per year. KMI is responsible for benefits accrued under its plans and allocates the related costs based on a benefit allocation rate applied on payroll charged to its affiliates.
	Postretirement Benefit Plans
	CIG and SNG provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and are subject to further benefit changes by KMI, the plan sponsor. In addition, certain former employees continue to receive limited postretirement life insurance benefits. Postretirement benefit plan costs are prefunded to the extent these costs are recoverable through rates. To the extent actual costs differ from the amounts recovered in rates, either "Accumulated other comprehensive income" or a regulatory asset or liability is recorded. We expect to make no contributions to our postretirement benefit plan in 2014. Contributions of approximately $1 million were made to the postretirement benefit plan for the years ended December 31, 2013, 2012 and 2011.
	Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status
	In accounting for the postretirement benefit plan, we record an asset or liability based on the overfunded or underfunded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either "Accumulated other comprehensive income" or a regulatory asset or liability. As part of the rate case settlement as discussed in Note 11, CIG will no longer include these costs in their rates.
	The table below provides information about the postretirement benefit plan (in millions):
		December 31,
		2013			2012
	Change in accumulated postretirement benefit obligation:
	Accumulated postretirement benefit obligation — beginning of period	$	63		$	55
	Interest cost	2			2
	Participant contributions	1			1
	Plan amendments	(19		)	—
	Actuarial (gain) loss	(4		)	10
	Benefits paid(a)	(4		)	(5		)
	Accumulated postretirement benefit obligation — end of period	$	39		$	63
	Change in plan assets:
	Fair value of plan assets — beginning of period	$	78		$	72
	Actual return on plan assets	9			9
	Employer contributions	1			1
	Participant contributions	1			1
	Benefits paid	(5		)	(5		)
	Fair value of plan assets — end of period	$	84		$	78
	Reconciliation of funded status:
	Fair value of plan assets	$	84		$	78
	Less: accumulated postretirement benefit obligation	39			63
	Net asset at December 31(b)	$	45		$	15
	——————
	(a)	Amount shown net of a subsidy of $1 million for the year ended December 31, 2013 and less than $1 million for the year ended December 31, 2012 related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
	(b)	Net asset amounts are included in "Deferred charges and other assets" in our Consolidated Balance Sheets.
	Components of Accumulated Other Comprehensive Income
	The amount recognized in "Accumulated other comprehensive income" for CIG as of December 31, 2013 and 2012 of $10 million for each period is primarily related to unrecognized gains. We anticipate that approximately $1 million of "Accumulated other comprehensive income" will be recognized as part of net periodic benefit income in 2014.
	Plan Assets
	The primary investment objective of the plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from the targeted allocations, the target allocations of the plan's assets are 70% equity and 30% fixed income securities.
	We use various methods to determine the fair values of the assets in the postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate the plan's assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2013, assets were comprised of domestic equity securities with a fair value of $3 million, a fixed income mutual fund with a fair value of $25 million and limited partnership funds with equity strategies with a fair value of $56 million. For the domestic equity securities, mutual fund and $29 million of the limited partnership funds, the fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the investment in actively traded markets. Approximately $27 million of the limited partnership balance is comprised of a limited partnership fund, for which the fair value (which is considered a Level 2 measurement) is determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. As of December 31, 2012, assets were comprised of a mutual fund with a fair value of $4 million and common/collective trust funds with a fair value of $74 million. The mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. The common/collective trust funds are invested in approximately 65% equity and 35% fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for the limited partnerships and common/collective trust funds where the issuer reserves the right to temporarily delay withdrawals in certain situations such as market conditions or at the issuer’s discretion. The plan does not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values. There have been no changes in the methodologies used at December 31, 2013 and 2012.
	Expected Payment of Future Benefits
	As of December 31, 2013, we expect the following benefit payments under the plan (in millions):
	Year Ending December 31,	Expected
		Payments
	2014	$	4
	2015	4
	2016	4
	2017	3
	2018	3
	2019 - 2023	14
	Actuarial Assumptions and Sensitivity Analysis
	Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining the postretirement plan's obligations and net benefit costs.
		2013		2012	2011
		(%)
	Assumptions related to benefit obligations at December 31:
	Discount rate	4.17		3.45	4.43
	Assumptions related to benefit costs for the year ended December 31:
	Discount rate(a)	3.62		4.25	4.9
	Expected return on plan assets(b)	7.5		7.5	7.75
	——————
	(a)	The discount rates related to benefit costs were 4.42% for the period from January 1, 2012 to May 24, 2012, and 4.12% for the period from May 25, 2012 to December 31, 2012.
	(b)	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes with a weighted average rate of 24% for 2013, 22% for 2012 and 35% for 2011.
	Actuarial estimates for the plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7%, gradually decreasing to 5% by the year 2019. A one-percentage point change would not have a significant effect on interest costs in 2013 and 2012. A one-percentage point change in assumed health care trends would not have a significant effect on the accumulated postretirement benefit obligation as of December 31, 2013 and would have the following effect as of December 31, 2012 (in millions):
		2012
	One percentage point increase:
	Accumulated postretirement benefit obligation	$	6
One percentage point decrease:
Accumulated postretirement benefit obligation	(5		)
Components of Net Benefit Income
For each of the years ended December 31, the components of net benefit income are as follows (in millions):
	2013			2012			2011
Interest cost	$	2		$	2		$	3
Expected return on plan assets	(7		)	(5		)	(4		)
Net benefit income	$	(5	)	$	(3	)	$	(1	)

Partners_Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Partners' Capital	'
	Partners’ Capital
	As of December 31, 2013, 2012 and 2011, our partners' capital included the following limited partner and general partner units:
			December 31,
			2013			2012			2011
	Common units:
	Held by third parties		127,510,832			125,468,515			117,298,691
	Held by KMI and affiliates		90,320,810			90,320,810			88,400,059
	Total limited partner units		217,831,642			215,789,325			205,698,750
	General partner units		4,445,455			4,403,765			4,197,822
	Total outstanding units		222,277,097			220,193,090			209,896,572
	As of December 31, 2013, KMI owns a 41% limited partner interest in us and retains its 2% general partner interest in us and all of our IDRs.
	The table below provides a reconciliation of our limited and general partner units.
		Unit Reconciliation
		Limited Partner Units						General			Total
								Partner			Partners’
		Common			Subordinated						Capital
	Balance at December 31, 2010	149,440,452			27,727,411			3,615,578			180,783,441
	Unit-based compensation to non-employee directors	5,481			—			—			5,481
	Conversion of subordinated units to common units(a)	27,727,411			(27,727,411	)		—			—
	Issuance of units	28,525,406			—			582,244			29,107,650
	Balance at December 31, 2011	205,698,750			—			4,197,822			209,896,572
	Unit-based compensation to non-employee directors	4,824			—			—			4,824
	Issuance of units	8,165,000			—			166,744			8,331,744
	Acquisition of interest in CPG and CIG	1,920,751			—			39,199			1,959,950
	Balance at December 31, 2012	215,789,325			—			4,403,765			220,193,090
	Unit-based compensation to non-employee directors	4,359			—			—			4,359
	Issuance of units	2,037,958			—			41,690			2,079,648
	Balance at December 31, 2013	217,831,642			—			4,445,455			222,277,097
	——————
	(a)	All subordinated units were converted to common units on a one-for-one basis effective January 3, 2011. See additional discussion below regarding subordinated units.
	Equity Issuances
	On March 7, 2013, we entered into an equity distribution agreement with Citigroup Global Markets, Inc. (Citigroup). Pursuant to the provisions of the equity distribution agreement, we may sell from time to time through Citigroup, as our sales agent, common units representing limited partner interests having an aggregate offering price of up to $500 million. Sales of the common units will be made by means of ordinary brokers' transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and Citigroup. Under the terms of the equity distribution agreement, we may also sell common units to Citigroup as principal for its own account at a price agreed upon at the time of the sale. Any sale of the common units to Citigroup as principal would be pursuant to the terms of a separate agreement between us and Citigroup. The equity distribution agreement provides us with the right, but not the obligation, to offer and sell common units, at prices to be determined by market conditions. We retain at all times complete control over the amount and the timing of each sale, and we will designate the maximum number of common units to be sold through Citigroup, on a daily basis or otherwise as we and Citigroup agree.
	We issued common units to the public and issued general partner units to KMI and affiliates. The net proceeds from the offerings were used as partial consideration to fund acquisitions from KMI and affiliates and general partnership purposes. The table below shows the units issued, the net proceeds for the issuances (in millions) and the ultimate use of the proceeds:
	Issuance Date		Common			General			Net Proceeds(d)			Use of Proceeds
			Units(b)			Partner
						Units(c)
	First Quarter 2011		13,800,000			281,725			$	467		Additional 25% interest in SNG
	Second Quarter 2011(a)		14,725,406			300,519			501			Additional 28% interest in CIG and remaining 15% interest in SNG
	Third Quarter 2012(a)		8,165,000			166,744			278			Repayment of CPG debt, certain short-term debt and general partnership purposes
	First Quarter 2013		525,900			10,831			22			General Partnership purposes
	Second Quarter 2013		1,512,058			30,859			65			General Partnership purposes
	——————
	(a)	Includes the underwriters’ exercise of the overallotment option.
	(b)	The 2013 issuances are pursuant to our equity distribution agreement.
	(c)	Units issued to the general partner to maintain its 2% ownership interest in us.
	(d)	Net proceeds include proceeds from issuances to our general partner.
	In addition, in May 2012, we issued 1,920,751 common units and 39,199 general partner units to El Paso in conjunction with our acquisition of CPG and the remainder of CIG. See Note 3 for further discussion.
	Earnings per Unit
	Earnings per unit is calculated based on distributions declared to our unitholders, including distributions related to the IDRs for the related reporting period. To the extent net income attributable to EPB exceeds cash distributions, the excess is allocated to unitholders and the holder of IDRs based on their contractual participation rights to share in those earnings. If cash distributions exceed net income attributable to EPB, the excess distributions are allocated proportionately to all participating units outstanding based on their respective ownership percentages. Additionally, the calculation of earnings per unit does not reflect an allocation of undistributed earnings to the IDR holders beyond amounts distributable under the terms of the partnership agreement. Payments made to our unitholders are determined in relation to actual declared distributions and are not based on the net income allocations used in the calculation of earnings per unit.
	As discussed in Note 3, we have retrospectively adjusted our historical financial statements for the consolidations of CPG following the acquisitions of its controlling interest. As a result of the retrospective consolidation, earnings prior to the acquisition of the incremental interest (pre-acquisition earnings) in CPG has been allocated solely to our general partner in all periods presented.
	Net income attributable to EPB per limited partner unit is computed by dividing the limited partners’ interest in net income attributable to EPB by the weighted average number of limited partner units outstanding. Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or other agreements to issue common units were exercised, settled or converted into common units. As of December 31, 2013 and 2012, the dilutive, restricted units outstanding were immaterial.
	Subordinated units
	All of the subordinated units were held by a wholly owned subsidiary of El Paso. Our partnership agreement provided that, during the subordination period, the common units would have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus were made on the subordinated units. Furthermore, no arrearages would be paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash to be distributed on the common units.
	Upon payment of the quarterly cash distribution payment for the fourth quarter of 2010, the financial tests required for the conversion of all subordinated units into common units were satisfied. As a result, all of the subordinated units held by affiliates of El Paso were converted on February 15, 2011 on a one-for-one basis into common units effective January 3, 2011. The conversion did not impact the amount of cash distribution paid or the total number of the Partnership’s outstanding units.
	Incentive Distribution Rights
	Our general partner, as the holder of our IDRs, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and (upon satisfaction of certain conditions) to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. In connection with this election, our general partner would be entitled to receive a number of newly issued Class B common units and general partner units based on a predetermined formula. In April 2012, the conditions were met which entitled our general partner to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are set. As of December 31, 2013, our general partner has not elected to reset its minimum quarterly distribution amount and increase the cash target distribution levels upon which its IDR payments are made. Therefore, no Class B units have been issued as required by the general partner's reset election. Even if there has been no reset election, diluted earnings per unit may be affected if the impact of a potential reset is dilutive. Currently, diluted earnings per unit has not been impacted because the combined impact is antidilutive.
	Our general partner currently holds all of our IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. The IDRs are considered a special non-voting limited partner interest under EPB's partnership agreement. For presentation purposes, we include income allocations and distributions related to the IDRs within general partner's capital because our general partner currently holds the IDRs. Based on the quarterly distribution per unit declared for the three months ended December 31, 2013, our general partner received an incentive distribution of $51 million on February 14, 2014 in accordance with the partnership agreement.
	Income Allocation and Declared Distributions
	For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner, who currently owns our IDRs. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash distributions made to all partners.
	Our partnership agreement requires that we distribute all of our available cash from operating surplus each quarter. We determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement summarized in the table below. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital necessary to maintain its 2% general partner interest and has not transferred its IDRs.
		Total Quarterly	Marginal Percentage
			Interest in Distribution
		Distribution per Unit	Unitholders	General
Target Amount		Partner
Minimum Quarterly Distribution	$0.29	98%	2%
First Target Distribution	above $0.2875 up to $0.33063	98%	2%
Second Target Distribution	above $0.33063 up to $0.35938	85%	15%
Third Target Distribution	above $0.35938 up to $0.43125	75%	25%
Thereafter	above $0.43125	50%	50%
The following table provides information about our distributions (in millions, except per unit distribution amounts):
	Year Ended December 31,
	2013				2012				2011
Per unit cash distributions declared for the period	$	2.55			$	2.25			$	1.93
Per unit cash distribution paid in the period(a)	2.51				2.14				1.87
Cash distributions paid in the period to all partners	746				564				422
General Partner's incentive distribution (b):
Declared for the period	195				129				62
Paid in the period(a)	187				105				49
——————
(a)	Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.
(b)	The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	Cash Distributions
	CIG Cash Distributions to El Paso
	CIG made quarterly distributions to its owners. We have reflected 42% of CIG’s distributions paid to El Paso through June 2011 and 14% thereafter as distributions to its noncontrolling interest holder until CIG became a wholly owned subsidiary of EPB subsequent to the May 2012 acquisition (see Note 3).
	SNG Cash Distributions to El Paso
	SNG makes quarterly distributions to its owners. We have reflected 40% of SNG’s distributions paid to El Paso through 2010 and 15% through the first quarter of 2011 as distributions to its noncontrolling interest holder. Subsequent to the June 2011 acquisition as described in Note 3, SNG became a wholly owned subsidiary of EPB.
	CPG Cash Distributions to El Paso
	Due to the retrospective consolidation of CPG, as discussed in Note 3, we have reflected CPG's historical distributions paid to El Paso prior to our consolidation in May 2012 as distributions of pre-acquisition earnings which are allocated solely to our general partner.
	The following table summarizes our cash distributions paid to El Paso prior to KMI's acquisition of El Paso (in millions):
		Year Ended December 31,
		2012			2011
	CIG distributions to noncontrolling interest holder	$	13		$	48
	SNG distributions to noncontrolling interest holder	—			31
	CPG distributions of pre-acquisition earnings	15			37
	Total Cash Distributions to El Paso	$	28		$	116
	Contributions to Subsidiaries
	During 2011, El Paso made capital contributions of $15 million to each of CIG and SNG, respectively, to fund their share of expansion project expenditures. In addition, prior to our acquisition of CPG, El Paso made a cash contribution to CPG in 2011 of $4 million. During 2012, El Paso made a capital contribution of $2 million to CIG to fund its share of expansion project expenditures.
	Contributions to Equity Method Investment
	During 2013, we made capital contributions of $13 million to ELC, our equity method investment, to fund its share of expansion project expenditures.
	Affiliate Balances
	We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to and from affiliates under long-term contracts and various operating agreements.
	We do not have employees. Employees of KMI and its affiliates provide services to our general partner, us and our subsidiaries. We are managed and operated by the directors and officers of our general partner, El Paso Pipeline GP Company, L.L.C., a subsidiary of KMI. Under an omnibus agreement with El Paso and other policies with KMI and its affiliates, we reimburse KMI and its affiliates without a profit component for the provision of various general and administrative services for our benefit and for direct expenses incurred by KMI or its affiliates on our behalf. KMI bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs without a profit component to us. Prior to KMI's acquisition of El Paso, we were allocated costs from EPNG and TGP, our affiliates, associated with our pipeline services. The allocations from TGP, EPNG and El Paso were based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, gross property and payroll.
	The following table summarizes our balance sheet affiliate balances (in millions):
			December 31,
			2013			2012
	Accounts receivable, net		$	3		$	7
	Natural gas imbalance receivable (a)		2			2
	Accounts payable		9			13
	Financing obligations(b)		175			178
	——————
	(a)	Included in "Other current assets" on our Consolidated Balance Sheets.
	(b)	Represents financing obligations payable to WYCO related to Totem and High Plains, of which $6 million and $5 million is included in "Current portion of debt" on our Consolidated Balance Sheets as of December 31, 2013 and 2012, respectively. See Note 5 for a further discussion of these obligations.
	The table below shows overall revenues, expenses and reimbursements from our affiliates for the years ended December 31, 2013, 2012 and 2011 (in millions):
		Year Ended December 31,
		2013			2012			2011
	Revenues	$	8		$	13		$	19
	Operating expenses(a)	156			224			242
	Reimbursement of operating expenses	—			3			4
	——————
	(a)	Includes non-cash severance costs of $1 million and $34 million for the years ended December 31, 2013 and 2012, respectively, allocated to us from our general partner as a result of KMI's acquisition of El Paso; however, we do not have any obligation nor did we pay any amounts related to this expense.

Litigation_Environmental_and_O

Litigation, Environmental and Other Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Litigation, Environmental and Other Contingencies	'
	Litigation, Environmental and Other Contingencies
	We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against us. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend these matters. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
	Legal Proceedings
	Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.
	In December 2011 (“Brinckerhoff I”), March 2012, (“Brinckerhoff II”) and May 2013 ("Brinckerhoff III"), derivative lawsuits were filed in Delaware Chancery Court against El Paso, El Paso Pipeline GP Company, L.L.C., our general partner and the directors of our general partner. We were named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010 and May 2012 drop down transactions involving our purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration we paid was excessive. Defendants' motion to dismiss in Brinckerhoff I was denied in part. Brinckerhoff I and II have been consolidated into one proceeding. The parties' motions for summary judgment are pending. A motion to dismiss has been filed in Brinckerhoff III. Defendants continue to believe that these actions are without merit and intend to defend against them vigorously.
	Allen v. El Paso Pipeline GP Company, L.L.C., et al.
	In May 2012, a unitholder of EPB filed a purported class action in Delaware Chancery Court, alleging both derivative and non-derivative claims, against us, and our general partner and its board. We were named in the lawsuit as both a “Class Defendant” and a “Derivative Nominal Defendant.” The complaint alleges a breach of the duty of good faith and fair dealing in connection with the March 2011 sale to us of a 25% ownership interest in SNG. Defendants' motion to dismiss was denied. Defendants' motion for summary judgment is pending. Defendants continue to believe this action is without merit and intend to defend against it vigorously.
	General
	As of December 31, 2013 and 2012, our total reserve for legal proceedings amounted to $2 million.
	Environmental Matters
	We are subject to environmental cleanup and enforcement actions from time to time. Our operations are subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in our operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
	Southeast Louisiana Flood Protection Litigation
	On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority- East filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against SNG, and approximately one hundred other energy companies, alleging that defendants' drilling, dredging, pipeline and industrial operations since the 1930's have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The Flood Protection Authority asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On September 10, 2013, the Flood Protection Authority filed a motion to remand the case to the state district court for Orleans Parish. On December 18, 2013, a hearing was conducted on the remand motion and it remains under consideration by the court.
	Superfund Matters
	Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated, as a PRP under the CERCLA, commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.
	General
	Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we are a party, will not have a material adverse effect on our business, financial position, results of operations or cash distributions. As of December 31, 2013 and 2012, we had approximately $2 million and $3 million accrued for our environmental matters.
	Other Commitments
	Capital Contributions for Elba Island Liquefaction Project
	In January 2013, SLC, a subsidiary of EPB and Shell G&P, a subsidiary of Royal Dutch Shell plc (Shell), formed ELC, our equity method investment, to develop and own a natural gas liquefaction plant at SLNG's existing Elba Island LNG terminal. In connection with the formation of ELC, SLC and Shell G&P entered into a LLC agreement in which SLC owns 51% of ELC and Shell G&P owns the remaining membership interest. Under the terms of the LLC agreement, SLC and Shell G&P are both obligated to make certain capital contributions in proportion to their membership interests in ELC to fund the construction of the liquefaction facilities. EPB's investment at the terminal in Phase I, including both the liquefaction facilities and SLNG ancillary facilities, is estimated to be approximately $800 million. Phase I of the project requires no additional DOE approval.
	Other Capital Commitments
	At December 31, 2013, we have capital commitments of approximately $5 million related to Southeast Supply Header, all of which will be spent in 2014. We also have commitments for the purchase of plant, property and equipment of $12 million, which we expect to spend during 2014. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
	Other Commercial Commitments
	We hold cancelable easement or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligations under these easements are not material to the results of our operations.
	Transportation and Storage Commitments
	We have entered into transportation commitments and storage capacity contracts totaling $239 million at December 31, 2013, of which $79 million and $8 million are related to storage capacity contracts with our affiliates, Young and Bear Creek, respectively. Our annual commitments under these agreements are $36 million in 2014, $28 million in 2015, $29 million in 2016, $29 million in 2017, $28 million in 2018 and $89 million in total thereafter.
	Operating Leases
	We lease property, facilities and equipment under various operating leases. Our minimum future annual rental commitments under our operating leases at December 31, 2013, are as follows (in millions):
	2014	$	4
	2015	4
	2016	4
	2017	4
	2018	4
	Thereafter	58
	Total minimum lease payments	$	78
	Rental expense on our operating leases for the year ended December 31, 2013 was $2 million and for each of the years ended December 31, 2012 and 2011 was $6 million and is reflected in "Operations and maintenance" expense on our Consolidated Statements of Income. While CIG and SNG hold the contractual obligations for the operating leases, the rent expense, which is considered a shared services cost and allocated to various KMI subsidiaries, is administered and funded by our parent, KMI. Our share of the rent expense is approximately 25% of the total KMI obligation.

Fair_Value

Fair Value	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value	'
	Fair Value
	The following table reflects the carrying amount and estimated fair values of our financial instruments (in millions):
		As of December 31,
		2013				2012
		Carrying		Estimated Fair Value		Carrying		Estimated Fair Value
		Amount				Amount
	Total debt, excluding other financing obligations(a)	$	4,073	$	4,441	$	4,161	$	4,895
	——————
	(a)	Our total other financing obligations were $175 million and $178 million as of December 31, 2013 and 2012, of which $6 million and $5 million was reported as "Current portion of debt" on our Consolidated Balance Sheets for each period.
	We separate the fair values of our financial instruments into levels based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the estimated fair value. We estimated the above fair values of debt, excluding total other financing obligations, primarily based on quoted market prices for the same or similar issues, a Level 2 fair value measurement. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and this change would be reflected at the end of the period in which the change occurs. During the years ended December 31, 2013 and 2012, there were no changes to the inputs and valuation techniques used to measure fair value of these instruments or the levels in which they were classified.
	As of December 31, 2013 and 2012, the carrying amounts of cash and cash equivalents, short-term borrowings and current receivables and payables represent fair value because of the short-term nature of these instruments.
	Interest Rate Derivatives
	In May 2005, CPG entered into two interest rate swap agreements, which were designated as cash flow hedges and effectively converted 80% of the $266 million term loan from a floating interest rate to a fixed interest rate. In September 2012, in conjunction with the repayment of the CPG term loan, we settled the outstanding balance of our accrued liabilities related to our interest rate swaps of approximately $12 million. There was no ineffectiveness recognized for these interest rate swaps during the periods ended December 31, 2012 and 2011. The $12 million loss on termination of these interest rate derivatives included in "Accumulated other comprehensive income" was deferred as a regulatory asset pursuant to the accounting requirements for regulated operations. The regulatory asset is amortized over the term of the original debt issuance and included as "Interest expense, net" on our Consolidated Statements of Income.

Accounting_for_Regulatory_Acti

Accounting for Regulatory Activities	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Accounting for Regulatory Assets and Liabilities	'
	Accounting for Regulatory Activities
	Regulatory Assets and Liabilities
	Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. As of December 31, 2013, the regulatory assets are being recovered as cost of service in our rates over a period of approximately one year to forty-two years. Below are the details of our regulatory assets and liabilities as of December 31 (in millions):
		2013		2012
	Current regulatory assets
	Differences between gas retained and gas consumed in operations	$	3	$	27
	Unamortized loss on sale of assets	13		13
	Other	10		6
	Total current regulatory assets	26		46
	Non-current regulatory assets
	Taxes on capitalized funds used during construction	76		78
	Unamortized loss on reacquired debt	30		41
	Unamortized loss on sale of assets	10		23
	Other	4		5
	Total non-current regulatory assets	120		147
	Total regulatory assets	$	146	$	193
	Current regulatory liabilities
	Differences between gas retained and gas consumed in operations	$	13	$	9
	Other	4		8
	Total current regulatory liabilities	17		17
	Non-current regulatory liabilities
	Property and plant retirements	8		8
	Postretirement benefits	37		12
	Other	15		13
	Total non-current regulatory liabilities(a)	60		33
	Total regulatory liabilities	$	77	$	50
	——————
	(a)	Included in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets.
	Our significant regulatory assets and liabilities include:
	Difference between gas retained and gas consumed in operations
	These amounts reflect the value of volumetric differences between gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers or returned to our customers in subsequent fuel filing periods.
	Taxes on capitalized funds used during construction
	These regulatory asset balances were established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long lived asset to which they relate. These balances were established on our pipelines prior to their conversion to non-taxable entities.
	Unamortized loss on reacquired debt
	Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered through the cost of service over the original life of the debt issue, or in the case of refinanced debt, over the life of the new debt issue.
	Unamortized loss on sale of assets
	Amount represents the deferred and unamortized portion of the loss on our sale of offshore assets. In accordance with the settlement of SNG's rate case, the recovery of the total regulatory asset will occur over a three-year period ending on October 31, 2015. See Note 3 for further discussion regarding SNG's asset divestiture.
	Postretirement benefits
	Represents unrecognized gains or losses related to SNG’s postretirement benefit plan. It also includes the differences between postretirement benefit amounts expensed and the amounts previously recovered in rates for CIG prior to its rate case settlement in August 2011. Prior to CIG’s rate case settlement, the balances also included unrecognized gains and losses or changes in actuarial assumptions related to its postretirement benefit plan. As part of the CIG rate case settlement, CIG no longer includes these costs in its rates and during 2011 reclassified approximately $9 million to "Accumulated other comprehensive income."
	Property and plant retirements
	Amount represents the deferral of customer-funded amounts for costs of future asset retirements.
	Regulatory Assets Amortization
	Our amortization of the regulatory assets for 2013 totaled $31 million, which primarily consisted of (i) $12 million of the deferred losses on SNG's sale of offshore assets recorded as "Depreciation and amortization" and (ii) $11 million of the deferred losses on reacquired debt recorded as "Interest expense, net" on our Consolidated Statement of Income.
	Rate Proceedings
	WIC
	The FERC initiated a rate proceeding on November 15, 2012 to investigate WIC's rates under Section 5 of the Natural Gas Act. On October 1, 2013, the FERC approved an uncontested Offer of Settlement filed in June 2013 by WIC to fully resolve FERC’s rate investigation. WIC’s approved settlement offer, agreed to by all active parties, provides for a two-phase, base tariff rate reduction on July 1, 2013 and January 1, 2014, as well as rate certainty for the parties during a three-year moratorium on new rates through July 1, 2016. The lower rates resulted in an annual revenue reduction of approximately $4 million in 2013 and are estimated to result in an additional $12 million reduction in 2014. The FERC order approving the uncontested settlement became effective November 1, 2013, and in December 2013 WIC made the rate refunds pursuant to the settlement.
	SNG
	On January 31, 2013, the FERC approved SNG's request to amend its January 2010 rate settlement with its customers. The amendment extended the required filing date for SNG's rate case from February 28, 2013 to no later than May 31, 2013. On May 2, 2013, SNG filed a comprehensive settlement with its customers to resolve all matters relating to its rates. The FERC approved the comprehensive settlement on July 12, 2013. Under the settlement, customers must extend all firm service agreements through August 31, 2016, and SNG cannot file a Section 4 rate case to be effective earlier than September 1, 2016. The settlement also includes a two-phase reduction in rates. The first phase, effective September 1, 2013, resulted in an approximately $11 million revenue reduction for 2013 and an additional revenue reduction of approximately $23 million for 2014. The second phase, effective November 1, 2015, will result in an additional revenue reduction of approximately $2 million for 2015 and an additional revenue reduction of approximately $12 million in 2016. The settlement prohibits both SNG and its customers from requesting a change to SNG's rates during a three-year moratorium through August 31, 2016 and requires SNG to file a new rate case to be effective no later than September 1, 2018.
	CIG
	In August 2011, the FERC approved an uncontested pre-filing settlement of a rate case required under the terms of a previous settlement. The settlement generally provides for (i) our current tariff rates to continue until our next general rate case which will be effective no earlier than October 1, 2014 but no later than October 1, 2016, (ii) contract extensions to March 2016, (iii) a revenue sharing mechanism with certain of our customers for certain revenues above annual threshold amounts and (iv) a revenue surcharge mechanism with certain of our customers to charge for certain shortfalls of revenue less than an annual threshold amount.

Transactions_with_Major_Custom

Transactions with Major Customers	12 Months Ended
	Dec. 31, 2013
Transactions with Major Customers [Abstract]	'
Transactions with Major Customers	'
	Transactions with Major Customers
	Our non-affiliate trade accounts receivable as of December 31, 2013 and 2012 were $143 million and $148 million, respectively. We had $1 million of other non-affiliate accounts receivable as of December 31, 2013 and none as of December 31, 2012. Our affiliate receivables are discussed in Note 8.
	The following table shows customers with revenues greater than 10% of our operating revenues, which we refer to as major customers, for each of the three years ended December 31 (in millions):
		2013		2012		2011
	Shell Oil Company and subsidiaries	$	220	$	220	$	221
	PSCo and subsidiary	170		169		170
	AGL Resources and subsidiaries	155		161		163
	At December 31, 2013, we have transportation and storage agreements with PSCo for capacity on High Plains through 2029 and Totem through 2040 each with annual firm revenue of $39 million.

Accounts_Receivable_Sales_Prog

Accounts Receivable Sales Program	12 Months Ended
	Dec. 31, 2013
Transfers and Servicing [Abstract]	'
Accounts Receivable Sales Program	'
	Accounts Receivable Sales Program
	We participated in accounts receivable sales programs where we sold receivables in their entirety to a third party financial institution (through wholly-owned special purpose entities). On June 20, 2012, we terminated the accounts receivable sales programs and paid $44 million to the third-party financial institution, which consisted of sales proceeds received up front and servicing fees. The sale of these accounts receivable (which were short-term assets that generally settled within 60 days) qualified for sale accounting. The third party financial institution involved in these accounts receivable sales programs acquired interests in various financial assets and issued commercial paper to fund those acquisitions. We did not consolidate the third party financial institution because we did not have the power to control, direct or exert significant influence over its overall activities since our receivables did not comprise a significant portion of its operations.
	In connection with our accounts receivable sales, we received a portion of the sales proceeds up front and received an additional amount upon the collection of the underlying receivables, which we referred to as a deferred purchase price. During 2012, we sold $418 million of accounts receivable to the third-party financial institution, for which we received $242 million of cash up front and had a deferred purchase price of $176 million. We received $191 million of cash when the underlying receivables were collected during 2012. Losses recognized on the sale of accounts receivable were immaterial for the years ended December 31, 2012 and 2011. There were no balances outstanding as of December 31, 2012 since all balances were settled in June 2012 when the accounts receivable sales programs were terminated.
	The deferred purchase price related to the accounts receivable sold was reflected as "Accounts receivable, net" on our Consolidated Balance Sheets. Because the cash received up front and the deferred purchase price related to the sale or ultimate collection of the underlying receivables, and were not subject to significant other risks given their short term nature, we reflected all cash flows under the accounts receivable sales programs as "Cash Provided by Operating Activities" on our Statements of Cash Flows. Under the accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements, as well as the fees earned, were not material to our financial statements for the years ended December 31, 2012 and 2011.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of Presentation	'
	Basis of Presentation
	We have prepared our accompanying consolidated financial statements under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB's Accounting Standards Codification, the single source of GAAP and referred to in this report as the Codification. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
	Additionally, our financial statements are consolidated into the consolidated financial statements of KMI. Also, except for the related party transactions described in Note 8, KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI's financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
Principles of Consolidation	'
	Principles of Consolidation
	We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity.  The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.
Use of Estimates	'
	Use of Estimates
	Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
	In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. Below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents	'
	Cash Equivalents
	We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Accounts Receivable	'
	Accounts Receivable
	The amounts reported as “Accounts receivable, net” on our accompanying Consolidated Balance Sheets at December 31, 2013 and 2012 primarily consist of amounts due from third party payors (unrelated entities). For information on receivables due to us from related parties, see Note 8.
	We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. The allowance for doubtful accounts as of December 31, 2013 and 2012 and the bad debt expense for the years ended December 31, 2013, 2012 and 2011 were not significant.
Inventories	'
	Inventories
	Our inventories, which consist of materials and supplies, are valued at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances	'
	Natural Gas Imbalances
	Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system differs from the scheduled amount of gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of the applicable FERC tariff. Imbalances due from others are reported in the Consolidated Balance Sheets as "Other current assets." Imbalances owed to others are reported in the Consolidated Balance Sheets as "Other current liabilities." We classify all imbalances as current as we expect them to be settled within a year.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Our indirect construction costs primarily include an interest and equity return component (as more fully described below) and labor and related costs of departments associated with supporting construction activities. The indirect capitalized labor and related costs are based upon estimates of time spent supporting construction projects.
	We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals the salvage value. For certain general plant, the asset is depreciated to zero. We re-evaluate depreciation rates each time we redevelop our transportation and storage rates to file with the FERC for an increase or decrease in rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not recognize gains or losses unless we sell or retire an entire operating unit, as determined by the FERC. We generally include gains or losses on dispositions of operating units in "Operations and maintenance" expense in our Consolidated Statements of Income. In those instances where we receive recovery in rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. See Note 3 for information related to a regulatory asset we recorded associated with the sale of certain SNG assets.
	Included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheets if deemed probable of recovery through future rates charged to customers.
	We capitalize a carrying cost (AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to "Interest expense, net" on our Consolidated Statements of Income. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in "Other, net" on our Consolidated Statements of Income.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses.  We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired.  Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets.  The liabilities are eventually extinguished when the asset is taken out of service.
	We are required to operate and maintain our natural gas pipelines, storage systems and LNG facilities, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline system assets and LNG facility assets because these assets have indeterminate lives.
	We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. Our asset retirement obligations were not significant as of December 31, 2013 and 2012.
Asset and Investment Divestitures/Impairments	'
	Asset and Investment Divestitures/Impairments
	We evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on either (i) the long-lived asset's ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value.
	Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.
	We classify assets (or groups of assets) to be disposed of as held for sale when specific criteria have been met. The lower of the carrying value or the estimated fair value less the cost to sell those assets is considered to determine if recognition of an impairment is required.  We cease depreciation and amortization of the assets in the period they are considered held for sale.
Equity Method of Accounting	'
	Equity Method of Accounting
	We account for investments, which we do not control but do have the ability to exercise significant influence, by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition costs, increased by our proportionate share of the investee's net income and by contributions made, and decreased by our proportionate share of the investee's net losses and by distributions received.
Revenue Recognition	'
	Revenue Recognition
	Our revenues are primarily generated from natural gas transportation, storage and processing services as well as from LNG storage services and terminal operations and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation services and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Gas not used in operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes.
	We recognize revenue from gas not used in operations from our shippers when the FERC allows us to retain the volumes at the market prices required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We had no reserves for potential refunds as of December 31, 2013 and 2012.
Environmental Matters	'
	Environmental Matters
	We expense or capitalize, as appropriate, environmental expenditures that relate to current operations.  We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation.  We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.  We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.
	We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts.  We also routinely adjust our environmental liabilities to reflect changes in previous estimates.  In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims.  Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.  These revisions are reflected in our income in the period in which they are reasonably determinable.  For more information on our environmental disclosures, see Note 9.
Legal	'
	Legal
	We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such litigation based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.  For more information on our legal disclosures, see Note 9.
Other Contingencies	'
	Other Contingencies
	We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue an undiscounted liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Postretirement Benefits	'
	Postretirement Benefits
	CIG and SNG, our consolidated subsidiaries, maintain a postretirement benefit plan covering certain of their former employees. The plan requires them to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. The net benefit cost of the plan is recorded in our Consolidated Statements of Income and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to CIG's and SNG's postretirement benefit plan, see Note 6.
	In accounting for CIG's and SNG's postretirement benefit plan, we record an asset or liability based on the difference between the fair value of the plan's assets and the plan's benefit obligation. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability or recorded as "Other comprehensive income" until those gains or losses are recognized on our Consolidated Statements of Income.
Noncontrolling Interests	'
	Noncontrolling Interests
	Noncontrolling interests represent the outstanding ownership interests in our consolidated operating limited partnerships that are not owned by us. In our accompanying Consolidated Statements of Income, the noncontrolling interests in our net income are shown as an allocation of our consolidated net income and are presented separately as “Net income attributable to noncontrolling interests.” In our accompanying Consolidated Balance Sheets, noncontrolling interests represent the ownership interests in our net assets held by parties other than us and are presented separately as “Noncontrolling interests.” For the year ended December 31, 2013, we had no non-wholly owned consolidated subsidiaries.
Limited Partners' Net Income per Unit	'
	Limited Partners' Net Income per Unit
	We compute “Limited partners' net income per unit” by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period.
Partners' Capital	'
	Partners' Capital
	We allocate our net income to the capital accounts of our general partner and limited partner unitholders based on the terms of the partnership agreement. The agreement requires these allocations to be made based on the relative percentage of their ownership interests, adjusted for any replenishment of previously allocated aggregate net losses and/or special allocations, each as defined in our partnership agreement. As a result of the retrospective consolidation of CIG, SNG and CPG, earnings prior to the acquisitions of the incremental interests in these subsidiaries (pre-acquisition earnings) have been allocated solely to our general partner. See Note 3 for additional information related to the retrospective consolidation of subsidiaries to reflect the reorganization of entities under common control and the change in reporting entity.
	Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities on the terms and conditions determined by our general partner without the approval of our unitholders. Accordingly, all of our issued units are authorized and outstanding, and there are an unlimited number of units that are authorized beyond those currently issued.
Regulated Operations	'
	Regulated Operations
	Our interstate natural gas pipelines, storage operations and LNG receiving terminal are subject to the jurisdiction of the FERC and follow the FASB's accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement benefit plan costs, losses on reacquired debt, losses on the sale of certain long lived assets, taxes related to an equity return component on regulated capital projects in periods prior to our subsidiaries' change in legal structure to non-taxable entities, certain cost differences between gas retained and gas consumed in operations and other costs included in, or expected to be included in, future rates. See Note 11 for further discussion regarding our regulated operations.

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	As of December 31, 2013 and 2012, our property plant and equipment consisted of the following (in millions, except for %):
		Annual Depreciation Rates	December 31,
		(%)	2013			2012
	Transmission and storage facilities	0.9-10.0	$	7,886		$	7,779
	General plant	1.76-25.0	66			67
	Intangible plant	1.76-23.0	126			128
	Other		196			202
	Accumulated depreciation and amortization(a)		(2,472		)	(2,321		)
			5,802			5,855
	Land		24			24
	Construction work in progress		53			52
	Property, plant and equipment, net		$	5,879		$	5,931
	——————
	(a)	The composite weighted average depreciation rates for the years ended December 31, 2013, 2012 and 2011 were 2.29%, 2.18% and 2.19%, respectively.

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Net carrying value of debt	'
	The following table summarizes the net carrying value of our outstanding debt (in millions):
		As of December 31,
		2013			2012
	EPPOC
	Senior Notes, 8.00%, due 2013	$	—		$	88
	Senior Notes, 4.10%, due 2015	375			375
	Senior Notes, 6.50%, due 2020	535			535
	Senior Notes, 5.00%, due 2021	500			500
	Senior Notes, 7.50%, due 2040	375			375
	Senior Notes, 4.70%, due 2042	475			475
	Revolving credit agreement, variable, due 2016(a)	—			—
	CIG
	Senior Notes, 5.95%, due 2015	35			35
	Senior Notes, 6.80%, due 2015	340			340
	Senior Debentures, 6.85%, due 2037	100			100
	SLNG
	Senior Notes, 9.50%, due 2014	71			71
	Senior Notes, 9.75%, due 2016	64			64
	SNG
	Notes, 5.90%, due 2017	500			500
	Notes, 4.40%, due 2021	300			300
	Notes, 7.35%, due 2031	153			153
	Notes, 8.00%, due 2032	258			258
	Total long-term debt	4,081			4,169
	Other financing obligations	175			178
	Total long-term debt and other financing obligations	4,256			4,347
	Less: Unamortized discount	8			8
	Current maturities	77			93
	Total long-term debt and other financing obligations, less current maturities	$	4,171		$	4,246
	——————
	(a)	LIBOR plus 1.75%.
Aggregate maturities of the principal amounts of debt	'
	The scheduled maturities of our outstanding debt as of December 31, 2013 are summarized as follows (in millions):
	Year		Commitment
	2014		$	77
	2015		756
	2016		69
	2017		505
	2018		5
	Thereafter		2,844
	Total long-term debt and other financing obligations		$	4,256

Retirement_Benefits_Tables

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Summary of information about the postretirement benefit plan	'
	The table below provides information about the postretirement benefit plan (in millions):
		December 31,
		2013			2012
	Change in accumulated postretirement benefit obligation:
	Accumulated postretirement benefit obligation — beginning of period	$	63		$	55
	Interest cost	2			2
	Participant contributions	1			1
	Plan amendments	(19		)	—
	Actuarial (gain) loss	(4		)	10
	Benefits paid(a)	(4		)	(5		)
	Accumulated postretirement benefit obligation — end of period	$	39		$	63
	Change in plan assets:
	Fair value of plan assets — beginning of period	$	78		$	72
	Actual return on plan assets	9			9
	Employer contributions	1			1
	Participant contributions	1			1
	Benefits paid	(5		)	(5		)
	Fair value of plan assets — end of period	$	84		$	78
	Reconciliation of funded status:
	Fair value of plan assets	$	84		$	78
	Less: accumulated postretirement benefit obligation	39			63
	Net asset at December 31(b)	$	45		$	15
	——————
	(a)	Amount shown net of a subsidy of $1 million for the year ended December 31, 2013 and less than $1 million for the year ended December 31, 2012 related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
	(b)	Net asset amounts are included in "Deferred charges and other assets" in our Consolidated Balance Sheets.
Summary of expected future benefit payments	'
	As of December 31, 2013, we expect the following benefit payments under the plan (in millions):
	Year Ending December 31,	Expected
		Payments
	2014	$	4
	2015	4
	2016	4
	2017	3
	2018	3
	2019 - 2023	14
Summary of weighted average actuarial assumptions used in determining the postretirement plan's obligations and net benefit costs	'
	The following table details the weighted average actuarial assumptions used in determining the postretirement plan's obligations and net benefit costs.
		2013		2012	2011
		(%)
	Assumptions related to benefit obligations at December 31:
	Discount rate	4.17		3.45	4.43
	Assumptions related to benefit costs for the year ended December 31:
	Discount rate(a)	3.62		4.25	4.9
	Expected return on plan assets(b)	7.5		7.5	7.75
	——————
	(a)	The discount rates related to benefit costs were 4.42% for the period from January 1, 2012 to May 24, 2012, and 4.12% for the period from May 25, 2012 to December 31, 2012.
	(b)	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes with a weighted average rate of 24% for 2013, 22% for 2012 and 35% for 2011.
Summary of one-percentage point change in assumed health care trends	'
	A one-percentage point change in assumed health care trends would not have a significant effect on the accumulated postretirement benefit obligation as of December 31, 2013 and would have the following effect as of December 31, 2012 (in millions):
		2012
	One percentage point increase:
	Accumulated postretirement benefit obligation	$	6
	One percentage point decrease:
	Accumulated postretirement benefit obligation	(5		)
Components of net benefit income	'
	For each of the years ended December 31, the components of net benefit income are as follows (in millions):
		2013			2012			2011
	Interest cost	$	2		$	2		$	3
	Expected return on plan assets	(7		)	(5		)	(4		)
	Net benefit income	$	(5	)	$	(3	)	$	(1	)

Partners_Capital_Tables

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of limited partner and general partner units in partners' capital	'
	As of December 31, 2013, 2012 and 2011, our partners' capital included the following limited partner and general partner units:
			December 31,
			2013			2012			2011
	Common units:
	Held by third parties		127,510,832			125,468,515			117,298,691
	Held by KMI and affiliates		90,320,810			90,320,810			88,400,059
	Total limited partner units		217,831,642			215,789,325			205,698,750
	General partner units		4,445,455			4,403,765			4,197,822
	Total outstanding units		222,277,097			220,193,090			209,896,572
Reconciliation of limited and general partner units	'
	The table below provides a reconciliation of our limited and general partner units.
		Unit Reconciliation
		Limited Partner Units						General			Total
								Partner			Partners’
		Common			Subordinated						Capital
	Balance at December 31, 2010	149,440,452			27,727,411			3,615,578			180,783,441
	Unit-based compensation to non-employee directors	5,481			—			—			5,481
	Conversion of subordinated units to common units(a)	27,727,411			(27,727,411	)		—			—
	Issuance of units	28,525,406			—			582,244			29,107,650
	Balance at December 31, 2011	205,698,750			—			4,197,822			209,896,572
	Unit-based compensation to non-employee directors	4,824			—			—			4,824
	Issuance of units	8,165,000			—			166,744			8,331,744
	Acquisition of interest in CPG and CIG	1,920,751			—			39,199			1,959,950
	Balance at December 31, 2012	215,789,325			—			4,403,765			220,193,090
	Unit-based compensation to non-employee directors	4,359			—			—			4,359
	Issuance of units	2,037,958			—			41,690			2,079,648
	Balance at December 31, 2013	217,831,642			—			4,445,455			222,277,097
	——————
	(a)	All subordinated units were converted to common units on a one-for-one basis effective January 3, 2011. See additional discussion below regarding subordinated units.
Schedule of issuances and net proceeds of common units	'
	The table below shows the units issued, the net proceeds for the issuances (in millions) and the ultimate use of the proceeds:
	Issuance Date		Common			General			Net Proceeds(d)			Use of Proceeds
			Units(b)			Partner
						Units(c)
	First Quarter 2011		13,800,000			281,725			$	467		Additional 25% interest in SNG
	Second Quarter 2011(a)		14,725,406			300,519			501			Additional 28% interest in CIG and remaining 15% interest in SNG
	Third Quarter 2012(a)		8,165,000			166,744			278			Repayment of CPG debt, certain short-term debt and general partnership purposes
	First Quarter 2013		525,900			10,831			22			General Partnership purposes
	Second Quarter 2013		1,512,058			30,859			65			General Partnership purposes
	——————
	(a)	Includes the underwriters’ exercise of the overallotment option.
	(b)	The 2013 issuances are pursuant to our equity distribution agreement.
	(c)	Units issued to the general partner to maintain its 2% ownership interest in us.
	(d)	Net proceeds include proceeds from issuances to our general partner.
Schedule of partnership quarterly distribution allocation	'
		Total Quarterly	Marginal Percentage
			Interest in Distribution
		Distribution per Unit	Unitholders	General
		Target Amount		Partner
	Minimum Quarterly Distribution	$0.29	98%	2%
	First Target Distribution	above $0.2875 up to $0.33063	98%	2%
	Second Target Distribution	above $0.33063 up to $0.35938	85%	15%
	Third Target Distribution	above $0.35938 up to $0.43125	75%	25%
	Thereafter	above $0.43125	50%	50%
Schedule of distributions to unitholders and general partner	'
	The following table provides information about our distributions (in millions, except per unit distribution amounts):
		Year Ended December 31,
		2013				2012				2011
	Per unit cash distributions declared for the period	$	2.55			$	2.25			$	1.93
	Per unit cash distribution paid in the period(a)	2.51				2.14				1.87
	Cash distributions paid in the period to all partners	746				564				422
	General Partner's incentive distribution (b):
	Declared for the period	195				129				62
	Paid in the period(a)	187				105				49
	——————
	(a)	Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.
	(b)	The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Summary of cash distributions paid to El Paso	'
	The following table summarizes our cash distributions paid to El Paso prior to KMI's acquisition of El Paso (in millions):
		Year Ended December 31,
		2012			2011
	CIG distributions to noncontrolling interest holder	$	13		$	48
	SNG distributions to noncontrolling interest holder	—			31
	CPG distributions of pre-acquisition earnings	15			37
	Total Cash Distributions to El Paso	$	28		$	116
Summary of balance sheet affiliate balances	'
	The following table summarizes our balance sheet affiliate balances (in millions):
			December 31,
			2013			2012
	Accounts receivable, net		$	3		$	7
	Natural gas imbalance receivable (a)		2			2
	Accounts payable		9			13
	Financing obligations(b)		175			178
	——————
	(a)	Included in "Other current assets" on our Consolidated Balance Sheets.
	(b)	Represents financing obligations payable to WYCO related to Totem and High Plains, of which $6 million and $5 million is included in "Current portion of debt" on our Consolidated Balance Sheets as of December 31, 2013 and 2012, respectively. See Note 5 for a further discussion of these obligations.
Affiliate Revenues and Expenses	'
	The table below shows overall revenues, expenses and reimbursements from our affiliates for the years ended December 31, 2013, 2012 and 2011 (in millions):
		Year Ended December 31,
		2013			2012			2011
	Revenues	$	8		$	13		$	19
	Operating expenses(a)	156			224			242
	Reimbursement of operating expenses	—			3			4
	——————
	(a)	Includes non-cash severance costs of $1 million and $34 million for the years ended December 31, 2013 and 2012, respectively, allocated to us from our general partner as a result of KMI's acquisition of El Paso; however, we do not have any obligation nor did we pay any amounts related to this expense.

Litigation_Environmental_and_O1

Litigation, Environmental and Other Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Summary of minimum future annual rental commitments under our operating leases	'
	Our minimum future annual rental commitments under our operating leases at December 31, 2013, are as follows (in millions):
	2014	$	4
	2015	4
	2016	4
	2017	4
	2018	4
	Thereafter	58
	Total minimum lease payments	$	78

Fair_Value_Tables

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial Instruments	'
	The following table reflects the carrying amount and estimated fair values of our financial instruments (in millions):
		As of December 31,
		2013				2012
		Carrying		Estimated Fair Value		Carrying		Estimated Fair Value
		Amount				Amount
	Total debt, excluding other financing obligations(a)	$	4,073	$	4,441	$	4,161	$	4,895
	——————
	(a)	Our total other financing obligations were $175 million and $178 million as of December 31, 2013 and 2012, of which $6 million and $5 million was reported as "Current portion of debt" on our Consolidated Balance Sheets for each period.

Accounting_for_Regulatory_Acti1

Accounting for Regulatory Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory assets and liabilities	'
	Below are the details of our regulatory assets and liabilities as of December 31 (in millions):
		2013		2012
	Current regulatory assets
	Differences between gas retained and gas consumed in operations	$	3	$	27
	Unamortized loss on sale of assets	13		13
	Other	10		6
	Total current regulatory assets	26		46
	Non-current regulatory assets
	Taxes on capitalized funds used during construction	76		78
	Unamortized loss on reacquired debt	30		41
	Unamortized loss on sale of assets	10		23
	Other	4		5
	Total non-current regulatory assets	120		147
	Total regulatory assets	$	146	$	193
	Current regulatory liabilities
	Differences between gas retained and gas consumed in operations	$	13	$	9
	Other	4		8
	Total current regulatory liabilities	17		17
	Non-current regulatory liabilities
	Property and plant retirements	8		8
	Postretirement benefits	37		12
	Other	15		13
	Total non-current regulatory liabilities(a)	60		33
	Total regulatory liabilities	$	77	$	50
	——————
	(a)	Included in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets.

Transactions_with_Major_Custom1

Transactions with Major Customers (Tables)	12 Months Ended
	Dec. 31, 2013
Transactions with Major Customers [Abstract]	'
Summary of revenues from major customers	'
	The following table shows customers with revenues greater than 10% of our operating revenues, which we refer to as major customers, for each of the three years ended December 31 (in millions):
		2013		2012		2011
	Shell Oil Company and subsidiaries	$	220	$	220	$	221
	PSCo and subsidiary	170		169		170
	AGL Resources and subsidiaries	155		161		163

General_Details_Textuals

General (Details Textuals)	Dec. 31, 2013
WYCO Development LLC [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]	'
Ownership interest in equity investments	50.00%
Bear Creek Storage Company LLC [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]	'
Ownership interest in equity investments	50.00%
Elba Liquefaction Company, L.L.C. [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]	'
Ownership interest in equity investments	51.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Original of maturity of short-term investments, less than three months	'3 months	'
Rate refund provision for rate proceedings	$0	$0
Number of non-wholly owned subsidiaries	0	'
General Plant [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant, and equipment, salvage value	$0	'

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Details) (USD $)

1 Months Ended

3 Months Ended

1 Months Ended

6 Months Ended

1 Months Ended

5 Months Ended

6 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2011

Mar. 31, 2011

Mar. 13, 2011

Jun. 29, 2011

Jun. 30, 2011

Jun. 30, 2011

31-May-12

Jun. 30, 2011

24-May-12

Dec. 31, 2011

Jun. 29, 2011

31-May-12

Dec. 31, 2012

Dec. 31, 2011

31-May-12

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

SNG and CIG [Member]

SNG and CIG [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

CPG and CIG [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

SNG and CIG [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business acquisition additional percentage of interest acquired

15.00%

25.00%

'

'

'

'

14.00%

28.00%

'

'

'

100.00%

'

'

'

'

'

'

Acquisition of additional ownership interest from El Paso in cash

'

$667

'

'

$745

'

$206

'

'

'

'

'

'

'

$571

'

'

'

Net proceeds from issuance of common and general partner units

'

467

'

'

501

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds From Lines Of Credit Used In Acquisition

'

200

'

'

244

'

'

'

'

'

'

'

'

'

570

'

'

'

Decrease in historical noncontrolling interest

'

'

'

'

'

896

'

'

115

'

'

'

'

'

'

'

'

'

Increase to General Partner's Capital from SNG and CIG acquisitions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

114

896

896

Percentage of general partner interest reflected as a noncontrolling interest

'

'

40.00%

15.00%

'

'

'

'

14.00%

14.00%

42.00%

'

'

'

'

'

'

'

Purchase price of the acquired business

'

'

'

'

'

'

'

'

'

'

'

'

'

'

635

'

'

'

Net proceeds from issuance of general partner units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

Additional interest acquired recorded at historical value

'

'

'

'

'

'

'

'

'

'

'

185

'

'

'

'

'

'

Excess cash paid over contributed book value

'

'

'

'

'

'

'

'

'

'

'

180

'

'

'

'

'

'

Increased net income after consolidation

'

'

'

'

'

'

'

'

'

'

'

'

$22

$40

'

'

'

'

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (Details Textuals) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Nov. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2011
				Southern Natural Gas Company [Member]	Southern Natural Gas Company [Member]	Southern Natural Gas Company [Member]	Southern Natural Gas Company [Member]
Divestitures (Textual) [Abstract]	'	'	'	'	'	'	'
SNG offshore and onshore assets held for sale	'	'	'	'	'	'	$50
SNG estimated loss deferred as regulatory asset	'	'	'	'	23	36	'
Proceeds from sale of assets	$0	$50	$1	$50	'	'	'

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details 1) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified					Transmission and Storage Facilities [Member]	Transmission and Storage Facilities [Member]	General Plant [Member]	General Plant [Member]	Intangible Plant [Member]	Intangible Plant [Member]
					Minimum [Member]	Maximum [Member]	Minimum [Member]	Maximum [Member]	Minimum [Member]	Maximum [Member]
Property, Plant and Equipment [Line Items]	'		'		'	'	'	'	'	'
Transmission and storage facilities	$7,886		$7,779		'	'	'	'	'	'
General plant	66		67		'	'	'	'	'	'
Intangible plant	126		128		'	'	'	'	'	'
Other	196		202		'	'	'	'	'	'
Accumulated depreciation and amortization	-2,472	[1]	-2,321	[1]	'	'	'	'	'	'
Depreciable plant assets	5,802		5,855		'	'	'	'	'	'
Land	24		24		'	'	'	'	'	'
Construction work in progress	53		52		'	'	'	'	'	'
Property, plant and equipment, net	$5,879		$5,931		'	'	'	'	'	'
Annual depreciation rates	'		'		0.90%	10.00%	1.76%	25.00%	1.76%	23.00%
[1]	The composite weighted average depreciation rates for the years ended DecemberB 31, 2013, 2012 and 2011 were 2.29%, 2.18% and 2.19%, respectively.

Property_Plant_and_Equipment_D1

Property, Plant and Equipment (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Abstract]	'	'	'
Composite weighted average depreciation rate	2.29%	2.18%	2.19%
Allowance for interest costs capitalized	$1	$1	$2
Allowance for equity amounts capitalized	$2	$3	$7

Debt_Details_1

Debt (Details 1) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

Senior Notes, 8.00%, due 2013 [Member]

Senior Notes, 8.00%, due 2013 [Member]

Senior Notes, 8.00%, due 2013 [Member]

Senior Notes, 4.10%, due 2015 [Member]

Senior Notes, 4.10%, due 2015 [Member]

Senior Notes, 6.50%, due 2020 [Member]

Senior Notes, 6.50%, due 2020 [Member]

Senior Notes, 5.00%, due 2021 [Member]

Senior Notes, 5.00%, due 2021 [Member]

Senior Notes, 7.50%, due 2040 [Member]

Senior Notes, 7.50%, due 2040 [Member]

Senior Notes 4.7%, due 2042 [Member]

Senior Notes 4.7%, due 2042 [Member]

Senior Notes 4.7%, due 2042 [Member]

Revolving Credit Agreement, variable, due 2016 [Member]

Revolving Credit Agreement, variable, due 2016 [Member]

Senior Notes, 5.95%, due 2015 [Member]

Senior Notes, 5.95%, due 2015 [Member]

Senior Notes, 6.80%, due 2015 [Member]

Senior Notes, 6.80%, due 2015 [Member]

Senior Debentures, 6.85%, due 2037 [Member]

Senior Debentures, 6.85%, due 2037 [Member]

Senior Notes, 9.50%, due 2014 [Member]

Senior Notes, 9.50%, due 2014 [Member]

Senior Notes, 9.75%, due 2016 [Member]

Senior Notes, 9.75%, due 2016 [Member]

Notes, 5.90%, due 2017 [Member]

Notes, 5.90%, due 2017 [Member]

Notes, 4.40%, Due 2021 [Member]

Notes, 4.40%, Due 2021 [Member]

Notes, 7.35%, due 2031 [Member]

Notes, 7.35%, due 2031 [Member]

Notes, 8.00%, due 2032 [Member]

Notes, 8.00%, due 2032 [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Colorado Interstate Gas Company, L.L.C [Member]

Southern LNG Company, L.L.C. [Member]

Southern LNG Company, L.L.C. [Member]

Southern LNG Company, L.L.C. [Member]

Southern LNG Company, L.L.C. [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Long term debt and other financing obligations [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt

$4,081

$4,169

$0

'

$88

$375

$375

$535

$535

$500

$500

$375

$375

$475

$475

'

'

'

$35

$35

$340

$340

$100

$100

$71

$71

$64

$64

$500

$500

$300

$300

$153

$153

$258

$258

Other financing obligations

175

178

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt and other financing obligations

4,256

4,347

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less: Unamortized discount

8

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current maturities

77

93

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt and other financing obligations, less current maturities

4,171

4,246

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit agreement, variable, due 2016

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0

[1]

$0

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long Term Debt And Other Financial Obligations (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate on notes issued

'

'

8.00%

8.00%

8.00%

4.10%

4.10%

6.50%

6.50%

5.00%

5.00%

7.50%

7.50%

4.70%

4.70%

4.70%

'

'

5.95%

5.95%

6.80%

6.80%

6.85%

6.85%

9.50%

9.50%

9.75%

9.75%

5.90%

5.90%

4.40%

4.40%

7.35%

7.35%

8.00%

8.00%

[1]

LIBOR plus 1.75%.

Debt_Details_2

Debt (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Long-term Debt, Fiscal Year Maturity [Abstract]	'	'
2014	$77	'
2015	756	'
2016	69	'
2017	505	'
2018	5	'
Thereafter	2,844	'
Total long-term debt and other financing obligations	$4,256	$4,347

Debt_Details_Textuals_1

Debt (Details Textuals 1) (El Paso Pipeline Partners Operating Company LLC [Member], USD $)	1 Months Ended	5 Months Ended	7 Months Ended		12 Months Ended
	31-May-11	24-May-12	Dec. 31, 2012		Dec. 31, 2013
Revolving Credit Agreement, variable, due 2016 [Member]	'	'	'		'
Line of Credit Facility [Line Items]	'	'	'		'
Line of credit agreement expiration period	'5 years	'	'		'
Revolving credit agreement aggregate borrowing capacity	$1,000,000,000	'	'		'
Revolving credit agreement aggregate maximum expandable capacity	1,500,000,000	'	'		'
Description of variable rate basis	'	'LIBOR	'LIBOR		'LIBOR
Basis spread on variable rate	'	2.00%	1.75%		1.75%
Previous percent of commitment fee paid	'	0.40%	'		'
Current percent of commitment fee paid	'	'	0.30%		0.03%
Revolving credit agreement, amount outstanding	'	'	0	[1]	0	[1]
Proceed from revolving credit agreement drawing	'	'	'		87,000,000
Repayments of revolving credit agreement	'	'	'		87,000,000
Revolving credit agreement, remaining availability	'	'	'		1,000,000,000
Maximum consolidated leverage ratio for any four consecutive quarters under line of credit agreement restrictive covenants description	'	'	'		'5.0 to 1.0
Maximum consolidated leverage ratio for any three consecutive quarters subsequent to consummation of specified permitted acquisitions under line of credit agreement restrictive covenants	'	'	'		'5.5 to 1.0
Minimum value of permitted acquisitions	'	'	'		25,000,000
Minimum amount required for the expansion of the project	'	'	'		20,000,000
Maximum percentage limit of proforma adjustments to actual consolidated EBITDA	'	'	'		25.00%
Maximum days allowed for nonpayment of principal or interest when due	'	'	'		'5 business days
Minimum amount of judgment default against the company	'	'	'		$50,000,000
Ownership percentage required of equity of EPPOC	'	'	'		100.00%
Fitch Ratings [Member] | Senior Notes [Member]	'	'	'		'
Line of Credit Facility [Line Items]	'	'	'		'
Debt Instrument, Credit Rating	'	'	'		'BBB-
Standard & Poor's Ratings [Member] | Senior Notes [Member]	'	'	'		'
Line of Credit Facility [Line Items]	'	'	'		'
Debt Instrument, Credit Rating	'	'	'		'BBB-
Moody's Investor Services Rating [Member] | Senior Notes [Member]	'	'	'		'
Line of Credit Facility [Line Items]	'	'	'		'
Debt Instrument, Credit Rating	'	'	'		'Ba1
[1]	LIBOR plus 1.75%.

Debt_Details_Textuals_2

Debt (Details Textuals 2) (USD $)

1 Months Ended

9 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2012

31-May-12

31-May-05

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Cheyenne Plains Gas Pipeline Company LLC [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

WYCO Development LLC [Member]

WYCO Development LLC [Member]

WYCO Development LLC [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes 4.7%, due 2042 [Member]

Senior Notes 4.7%, due 2042 [Member]

Senior Notes 4.7%, due 2042 [Member]

Senior Notes, 8.00%, due 2013 [Member]

Senior Notes, 8.00%, due 2013 [Member]

Senior Notes, 8.00%, due 2013 [Member]

Totem Gas Storage obligation [Member]

High Plains Pipeline obligation [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

Southern LNG Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

El Paso Pipeline Partners Operating Company, L.L.C. [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other EPB debt obligations, parent company percentage of total consolidated amounts

'

'

'

'

'

'

'

'less than 3%

'

'

'

'

'

'

'

Aggregate principal amount of notes issued

'

'

'

'

'

'

'

'

'

$475

'

'

'

'

'

Interest rate on notes issued

'

'

'

'

'

'

'

'

'

4.70%

4.70%

4.70%

8.00%

8.00%

8.00%

Net proceeds from issuance of new senior notes

'

'

'

'

'

'

'

'

'

469

'

'

'

'

'

Repayments of long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

88

'

'

Maximum simple leverage ratio, financial covenant

'

'

'

'

'

'

'

'

'5.0 to 1.0

'

'

'

'

'

'

Minimum interest coverage ratio, financial covenant

'

'

'

'

'

'

'

'

'2.0 to 1.0

'

'

'

'

'

'

Percentage of principal amount of notes redeemed

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

Period of extension of change of control prepayment offer

'

'

'

'

'

'

'

'

'120 days

'

'

'

'

'

'

Percentage of unpaid principal amount notes

'

'

'

'

'

'

'

'

101.00%

'

'

'

'

'

'

Nonrecourse project financing agreement

'

266

266

'

'

'

'

'

'

'

'

'

'

'

'

Maturity date of nonrecourse project financing agreement

'

'

31-Mar-15

'

'

'

'

'

'

'

'

'

'

'

'

CPG principal payments

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

CPG debt payoff amount

172

'

'

'

'

'

'

'

'

'

'

'

'

'

'

CPG letters of credit canceled

12

'

'

12

'

'

'

'

'

'

'

'

'

'

'

Long-Term Debt and Other Financing Obligations (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of construction costs

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

Percent of advanced payments received from joint venture partner

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

Principal amounts of other financing obligations

'

'

'

'

'

$75

$94

'

'

'

'

'

'

'

'

Period of principal payments of other financing obligations

'

'

'

'

'

'2039 through 2060

'2039 through 2043

'

'

'

'

'

'

'

'

Effective interest rate on monthly interest payments of other financing obligations

'

'

'

'

'

15.50%

15.50%

'

'

'

'

'

'

'

'

Retirement_Benefits_Details_1

Retirement Benefits (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Change in accumulated postretirement benefit obligation:	'		'		'
Accumulated postretirement benefit obligation - beginning of period	$63		$55		'
Interest cost	2		2		3
Participant contributions	1		1		'
Plan amendments	-19		0		'
Actuarial (gain) loss	-4		10		'
Benefits paid	-4	[1]	-5	[1]	'
Accumulated postretirement benefit obligation - end of period	39		63		55
Change in plan assets:	'		'		'
Fair value of plan assets - beginning of period	78		72		'
Actual return on plan assets	9		9		'
Employer contributions	1		1		1
Participant contributions	1		1		'
Benefits paid	-5		-5		'
Fair value of plan assets - end of period	84		78		72
Reconciliation of funded status:	'		'		'
Fair value of plan assets	84		78		72
Less: accumulated postretirement benefit obligation	39		63		55
Net asset at December 31	$45	[2]	$15	[2]	'
[1]	Amount shown net of a subsidy of $1 million for the year ended DecemberB 31, 2013 and less than $1 million for the year ended DecemberB 31, 2012 related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
[2]	Net asset amounts are included in "Deferred charges and other assets" in our Consolidated Balance Sheets.

Retirement_Benefits_Details_2

Retirement Benefits (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Summary of expected future benefit payments	'
2014	$4
2015	4
2016	4
2017	3
2018	3
2019 - 2022	$14

Retirement_Benefits_Details_3

Retirement Benefits (Details 3)	5 Months Ended	7 Months Ended	12 Months Ended
	24-May-12	Dec. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Assumptions related to benefit obligations at December 31:	'	'	'		'		'
Discount rate	'	3.45%	4.17%		3.45%		4.43%
Assumptions related to benefit costs for the year ended December 31:	'	'	'		'		'
Discount rate	4.42%	4.12%	3.62%	[1]	4.25%	[1]	4.90%	[1]
Expected return on plan assets	'	'	7.50%	[2]	7.50%	[2]	7.75%	[2]
[1]	The discount rates related to benefit costs were 4.42% for the period from January 1, 2012 to May 24, 2012, and 4.12% for the period from May 25, 2012 to December 31, 2012.
[2]	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes with a weighted average rate of 24% for 2013, 22% for 2012 and 35% for 2011.

Retirement_Benefits_Details_4

Retirement Benefits (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
One percentage point increase:	'
Accumulated postretirement benefit obligation	$6
One percentage point decrease:	'
Accumulated postretirement benefit obligation	($5)

Retirement_Benefits_Details_5

Retirement Benefits (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of net benefit income	'	'	'
Interest cost	$2	$2	$3
Expected return on plan assets	-7	-5	-4
Net benefit income	($5)	($3)	($1)

Retirement_Benefits_Details_Te

Retirement Benefits (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Compensation and Retirement Disclosure [Abstract]	'	'	'
Percentage of participant's eligible compensation contributed by KMI to the retirement savings plan	5.00%	'	'
Expected contribution to the postretirement benefit plans	$0	'	'
Contribution made to the postretirement benefit plans	1	1	1
Amount accumulated for subsidy related to prescription drug benefits ($1 million for 2013 and Less than $1 million for 2012)	1	1	'
Unrecognized gains recorded in accumulated other comprehensive income	10	10	'
Amount of accumulated other comprehensive income recognized as net periodic benefit income in 2014	1	'	'
Weighted average income tax rate	24.00%	22.00%	35.00%
Weighted average annual rate of increase in the per capita costs of covered health care benefits	7.00%	'	'
Weighted average annual rate of decrease in the per capita costs of covered health care benefits	5.00%	'	'
Defined benefit plan, year that rate reaches Ultimate Trend Rate	'2019	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	84	78	72
Equity Securities [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Percentage of target allocations of the plans' assets	70.00%	'	'
Percentage of common collective trust fund investments to equity or fixed income securities	'	65.00%	'
Fixed Income Securities [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Percentage of target allocations of the plans' assets	30.00%	'	'
Percentage of common collective trust fund investments to equity or fixed income securities	'	35.00%	'
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	3	'	'
Fixed Income Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	25	'	'
Common/collective trust funds [Member] | Fair Value, Inputs, Level 2 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	'	74	'
Mutual fund [Member] | Fair Value, Inputs, Level 1 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	'	4	'
Limited Partnership Funds with Equity Strategies [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	56	'	'
Limited Partnership Funds with Equity Strategies [Member] | Fair Value, Inputs, Level 1 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	29	'	'
Limited Partnership Funds with Equity Strategies [Member] | Fair Value, Inputs, Level 2 [Member]	'	'	'
Defined Benefit Plan, Information about Plan Assets [Abstract]	'	'	'
Fair value of plan assets	$27	'	'

Partners_Capital_Details_1

Partners' Capital (Details 1)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of limited partner and general partner units in partners' capital	'	'	'	'
Held by third parties	127,510,832	125,468,515	117,298,691	'
Held by KMI and affiliates	90,320,810	90,320,810	88,400,059	'
Total limited partner units	217,831,642	215,789,325	205,698,750	'
General partner units	4,445,455	4,403,765	4,197,822	'
Total outstanding units	222,277,097	220,193,090	209,896,572	180,783,441

Partners_Capital_Details_2

Partners' Capital (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of limited and general partner units	'	'	'
Beginning Balance, Units	220,193,090	209,896,572	180,783,441
Unit-based compensation to non-employee directors	4,359	4,824	5,481
Conversion of subordinated units to common units	'	'	0
Issuance of units	2,079,648	8,331,744	29,107,650
Units issued to acquire interests in CPG and CIG	'	1,959,950	'
Ending Balance, Units	222,277,097	220,193,090	209,896,572
Limited partner common units [Member]	'	'	'
Reconciliation of limited and general partner units	'	'	'
Beginning Balance, Units	215,789,325	205,698,750	149,440,452
Unit-based compensation to non-employee directors	4,359	4,824	5,481
Conversion of subordinated units to common units	'	'	27,727,411	[1]
Issuance of units	2,037,958	8,165,000	28,525,406
Units issued to acquire interests in CPG and CIG	'	1,920,751	'
Ending Balance, Units	217,831,642	215,789,325	205,698,750
Limited partner subordinated units [Member]	'	'	'
Reconciliation of limited and general partner units	'	'	'
Beginning Balance, Units	0	0	27,727,411
Unit-based compensation to non-employee directors	0	0	0
Conversion of subordinated units to common units	'	'	-27,727,411	[1]
Issuance of units	0	0	0
Units issued to acquire interests in CPG and CIG	'	0	'
Ending Balance, Units	0	0	0
General Partner [Member]	'	'	'
Reconciliation of limited and general partner units	'	'	'
Beginning Balance, Units	4,403,765	4,197,822	3,615,578
Unit-based compensation to non-employee directors	0	0	0
Conversion of subordinated units to common units	'	'	0
Issuance of units	41,690	166,744	582,244
Units issued to acquire interests in CPG and CIG	'	39,199	'
Ending Balance, Units	4,445,455	4,403,765	4,197,822
[1]	All subordinated units were converted to common units on a one-for-one basis effective JanuaryB 3, 2011. See additional discussion below regarding subordinated units.

Partners_Capital_Details_3

Partners' Capital (Details 3) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2011

Jun. 30, 2011

Sep. 30, 2012

Mar. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2011

Jun. 30, 2011

Sep. 30, 2012

Mar. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2011

Jun. 30, 2011

Sep. 30, 2012

Mar. 31, 2013

Jun. 30, 2013

Issuance Date Q1 2011 [Member]

Issuance Date Q2 2011 [Member]

Issuance Date Q3 2012 [Member]

Issuance Date Q1 2013 [Member]

Issuance Date Q2 2013 [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

Issuance Date Q1 2011 [Member]

Issuance Date Q2 2011 [Member]

Issuance Date Q3 2012 [Member]

Issuance Date Q1 2013 [Member]

Issuance Date Q2 2013 [Member]

Issuance Date Q1 2011 [Member]

Issuance Date Q2 2011 [Member]

Issuance Date Q3 2012 [Member]

Issuance Date Q1 2013 [Member]

Issuance Date Q2 2013 [Member]

Schedule of issuances and net Proceeds of common units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of units

2,079,648

8,331,744

29,107,650

'

'

'

'

'

2,037,958

8,165,000

28,525,406

13,800,000

14,725,406

[1]

8,165,000

[1]

525,900

[2]

1,512,058

[2]

41,690

166,744

582,244

281,725

300,519

[1]

166,744

[1]

10,831

[3]

30,859

[3]

Net Proceeds

$87

$279

$968

$467

$501

[1]

$278

[1]

$22

[4]

$65

[4]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Use of proceeds

'

'

'

'Additional 25% interest in SNG

'Additional 28% interest in CIG and remaining 15% interest in SNG

'Repayment of CPG debt, certain short-term debt and general partnership purposes

'General Partnership purposes

'General Partnership purposes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Includes the underwritersb exercise of the overallotment option.

[2]

The 2013 issuances are pursuant to our equity distribution agreement.

[3]

Units issued to the general partner to maintain its 2% ownership interest in us.

[4]

Net proceeds include proceeds from issuances to our general partner.

Partners_Capital_Details_4

Partners' Capital (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013
Minimum Quarterly Distribution [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Marginal percentage interest in distributions - Unitholders	98.00%
Marginal percentage interest in distributions - General Partner	2.00%
Minimum Quarterly Distribution [Member] | Minimum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.2875
First Target Distribution [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Marginal percentage interest in distributions - Unitholders	98.00%
Marginal percentage interest in distributions - General Partner	2.00%
First Target Distribution [Member] | Minimum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.2875
First Target Distribution [Member] | Maximum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.33063
Second Target Distribution [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Marginal percentage interest in distributions - Unitholders	85.00%
Marginal percentage interest in distributions - General Partner	15.00%
Second Target Distribution [Member] | Minimum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.33063
Second Target Distribution [Member] | Maximum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.35938
Third Target Distribution [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Marginal percentage interest in distributions - Unitholders	75.00%
Marginal percentage interest in distributions - General Partner	25.00%
Third Target Distribution [Member] | Minimum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.35938
Third Target Distribution [Member] | Maximum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.43125
Thereafter Target Distribution [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Marginal percentage interest in distributions - Unitholders	50.00%
Marginal percentage interest in distributions - General Partner	50.00%
Thereafter Target Distribution [Member] | Minimum [Member]	'
Schedule of partnership quarterly distribution allocation [Line Items]	'
Total quarterly distribution per unit target amount	0.43125

Partners_Capital_Details_5

Partners' Capital (Details 5) (USD $)	3 Months Ended	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Summary of distributions to unit holders and general partner	'	'		'		'
Per unit cash distributions declared for the period	'	$2.55		$2.25		$1.93
Per unit cash distribution paid in the period	'	$2.51	[1]	$2.14	[1]	$1.87	[1]
Cash distributions paid in the period to all partners	'	$746		$564		$422
General Partner's incentive distribution:	'	'		'		'
Declared for the period	'	195	[2]	129	[2]	62	[2]
Paid in the period	$51	$187	[1],[2]	$105	[1],[2]	$49	[1],[2]
[1]	Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.
[2]	The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units.

Partners_Capital_Details_Textu

Partners' Capital (Details Textual) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

In Millions, except Share data, unless otherwise specified

Feb. 15, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 07, 2013

Dec. 31, 2012

Dec. 31, 2012

31-May-12

31-May-12

Common Units [Member]

General Partner [Member]

CIG and CPG [Member]

CIG and CPG [Member]

Common Units [Member]

General Partner [Member]

Schedule of Equity Issued Since Inception [Line Items]

'

'

'

'

'

'

'

'

'

'

Units issued to acquire interests in CPG and CIG

'

'

'

1,959,950

'

'

1,920,751

39,199

1,920,751

39,199

Partners Capital (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

Percentage of limited partner interest

'

'

41.00%

'

'

'

'

'

'

'

Percentage of general partner interest

'

'

2.00%

2.00%

2.00%

'

'

'

'

'

Converted subordinated units held by El Paso

'one-for-one basis

'

'

'

'

'

'

'

'

'

Value of units available for sale under equity distribution agreement with Citigroup

'

'

'

'

'

$500

'

'

'

'

Distributions of available cash from operating surplus during subordination period (minimum quarterly distribution per common unit)

'

'

'

'

$0.29

'

'

'

'

'

General Partner's Incentive Distribution

'

$51

$187

[1],[2]

$105

[1],[2]

$49

[1],[2]

'

'

'

'

'

Class B units issued

'

0

0

'

'

'

'

'

'

'

Incentive distributions to general partners

'

'

100.00%

'

'

'

'

'

'

'

Basis of incentive distribution to general partners

'

'

'in excess of 2% of the aggregate value of cash distributions

'

'

'

'

'

'

'

[1]

The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units.

[2]

Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

Related_Party_Transactions_Det

Related Party Transactions (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Summary of cash distributions paid to El Paso	'	'
Total cash distributions to El Paso	$28	$116
Colorado Interstate Gas Company LLC [Member]	'	'
Summary of cash distributions paid to El Paso	'	'
Distributions to noncontrolling Interest holder	13	48
Southern Natural Gas Company [Member]	'	'
Summary of cash distributions paid to El Paso	'	'
Distributions to noncontrolling Interest holder	0	31
Cheyenne Plains Gas Pipeline Company LLC [Member]	'	'
Summary of cash distributions paid to El Paso	'	'
CPG distributions of pre-acquisition earnings	$15	$37

Related_Party_Transactions_Det1

Related Party Transactions (Details 2) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Summary of balance sheet affiliate balances	'		'
Accounts receivable, net	$3		$7
Natural gas imbalance receivable	2	[1]	2	[1]
Accounts payable	9		13
Financing obligations	$175	[2]	$178	[2]
[1]	Included in "Other current assets" on our Consolidated Balance Sheets.
[2]	Represents financing obligations payable to WYCO related to Totem and High Plains, of which $6 million and $5 million is included in "Current portion of debt" on our Consolidated Balance Sheets as of DecemberB 31, 2013 and 2012, respectively. See Note 5 for a further discussion of these obligations.

Related_Party_Transactions_Det2

Related Party Transactions (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Affiliate revenues and expenses	'		'		'
Revenues	$8		$13		$19
Operating expenses	156	[1]	224	[1]	242
Reimbursement of operating expenses	$0		$3		$4
[1]	Includes non-cash severance costs of $1 million and $34 million for the years ended DecemberB 31, 2013 and 2012, respectively, allocated to us from our general partner as a result of KMI's acquisition of El Paso; however, we do not have any obligation nor did we pay any amounts related to this expense

Related_Party_Transactions_Det3

Related Party Transactions (Details Textual) (USD $)

12 Months Ended

5 Months Ended

6 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

24-May-12

Dec. 31, 2011

Jun. 30, 2011

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2011

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2011

Colorado Interstate Gas Company L.L.C [Member]

Colorado Interstate Gas Company L.L.C [Member]

Colorado Interstate Gas Company L.L.C [Member]

Colorado Interstate Gas Company L.L.C [Member]

Colorado Interstate Gas Company L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Southern Natural Gas Company, L.L.C [Member]

Cheyenne Plains Gas Pipeline Company LLC [Member]

Related Party Transactions (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of distributions paid to El Paso

'

'

'

14.00%

14.00%

42.00%

'

'

15.00%

'

40.00%

'

Cash contributions to subsidiaries from El Paso

$0

$2

$34

'

'

'

$2

$15

'

$15

'

$4

Capital contributions to ELC

13

'

'

'

'

'

'

'

'

'

'

'

Financing obligations payable to WYCO related to Totem and High Plains, current

6

5

'

'

'

'

'

'

'

'

'

'

Non-cash severance costs

$1

$34

$0

'

'

'

'

'

'

'

'

'

Litigation_Environmental_and_O2

Litigation, Environmental and Other Contingencies (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Summary of minimum future annual rental commitments under our operating leases	'
2014	$4
2015	4
2016	4
2017	4
2018	4
Thereafter	58
Total minimum lease payments	$78

Litigation_Environmental_and_O3

Litigation, Environmental and Other Contingencies (Details Textual) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	31-May-12	Dec. 31, 2013
	site			Southern Natural Gas Company [Member]	Elba Liquefaction Company, L.L.C. [Member]
Commitments and Contingencies (Textual) [Abstract]	'	'	'	'	'
Business acquisition percentage of additional interest	'	'	'	25.00%	'
Accrued outstanding legal proceedings	$2	$2	'	'	'
Active superfund site	1	'	'	'	'
Accrued environmental liabilities	2	3	'	'	'
Ownership interest in equity investments	'	'	'	'	51.00%
EPB's portion of the capital expenditures for Phase I Elba Liquefaction construction	800	'	'	'	'
Rental expense on operating leases	$2	$6	$6	'	'
Rent expense on operating lease allocation percentage	25.00%	'	'	'	'

Litigation_Environmental_and_O4

Litigation, Environmental and Other Contingencies (Details Textuals 1) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Capital Commitments [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Unconditional purchase obligations at 2013	$5
Plant, Property and Equipment [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Unconditional purchase obligations at 2013	12
Transportation And Storage Commitments [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Unconditional purchase obligations at 2013	239
Unconditional annual purchase obligations in 2014	36
Unconditional annual purchase obligations in 2015	28
Unconditional annual purchase obligations in 2016	29
Unconditional annual purchase obligations in 2017	29
Unconditional annual purchase obligations in 2018	28
Unconditional annual purchase obligations thereafter	89
Transportation And Storage Commitments [Member] | Young Gas Storage Company Ltd [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Unconditional purchase obligations at 2013	79
Transportation And Storage Commitments [Member] | Bear Creek Storage Company, LLC [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Unconditional purchase obligations at 2013	$8

Fair_Value_Details

Fair Value (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Financial Instruments	'		'
Total debt, excluding other financing obligations, Carrying Amount	$4,073	[1]	$4,161	[1]
Total debt, excluding other financing obligations, Fair Value	$4,441	[1]	$4,895	[1]
[1]	Our total other financing obligations were $175 million and $178 million as of DecemberB 31, 2013 and 2012, of which $6 million and $5 million was reported as "Current portion of debt" on our Consolidated Balance Sheets for each period.

Fair_Value_Details_Textual

Fair Value (Details Textual) (USD $)	Dec. 31, 2013	Dec. 31, 2012	31-May-12	31-May-05	Sep. 30, 2012	Sep. 30, 2012	Dec. 31, 2011	31-May-05
In Millions, unless otherwise specified			Cheyenne Plains Gas Pipeline Company LLC [Member]	Cheyenne Plains Gas Pipeline Company LLC [Member]	Cheyenne Plains Gas Pipeline Company LLC [Member]	Cheyenne Plains Gas Pipeline Company LLC [Member]	Cheyenne Plains Gas Pipeline Company LLC [Member]	Cheyenne Plains Gas Pipeline Company LLC [Member]
					Interest Rate Swap [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]	Interest Rate Swap [Member]
Fair Value (Textual) [Abstract]	'	'	'	'	'	'	'	'
Other financing obligations	$175	$178	'	'	'	'	'	'
Other financing obligations, current	6	5	'	'	'	'	'	'
Interest rate swap agreements	'	'	'	'	'	'	'	2
Fixed percent of the term loan	'	'	'	80.00%	'	'	'	'
Nonrecourse project financing agreement	'	'	266	266	'	'	'	'
Settlement of CPG hedge liabilities	'	'	'	'	12	'	'	'
Loss on cash flow hedge ineffectiveness	'	'	'	'	'	0	0	'
Loss on terminated derivatives deferred to regulatory asset	'	'	'	'	$12	$12	'	'

Accounting_for_Regulatory_Acti2

Accounting for Regulatory Activities (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Summary of our regulatory assets and liabilities	'		'
Total current regulatory assets	$26		$46
Total non-current regulatory assets	120		147
Total regulatory assets	146		193
Total current regulatory liabilities	17		17
Total non-current regulatory liabilities	60	[1]	33	[1]
Total regulatory liabilities	77		50
Differences between gas retained and gas consumed in operations [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total current regulatory liabilities	13		9
Other [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total current regulatory liabilities	4		8
Total non-current regulatory liabilities	15		13
Property and plant retirements [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total non-current regulatory liabilities	8		8
Postretirement benefits [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total non-current regulatory liabilities	37		12
Differences between gas retained and gas consumed in operations [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total current regulatory assets	3		27
Unamortized loss on sale of assets [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total current regulatory assets	13		13
Total non-current regulatory assets	10		23
Other [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total current regulatory assets	10		6
Total non-current regulatory assets	4		5
Taxes on capitalized funds used during construction [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total non-current regulatory assets	76		78
Unamortized loss on reacquired debt [Member]	'		'
Summary of our regulatory assets and liabilities	'		'
Total non-current regulatory assets	$30		$41
[1]	Included in bOther long-term liabilities and deferred creditsb on our Consolidated Balance Sheets.

Accounting_for_Regulatory_Acti3

Accounting for Regulatory Activities (Details Textuals) (USD $)

12 Months Ended

4 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Deferred Losses On Sale Of Assets [Member]

Loss on Reacquired Debt [Member]

Maximum [Member]

Minimum [Member]

Southern Natural Gas Company [Member]

Phase I [Member]

Phase I [Member]

Phase II [Member]

Phase II [Member]

Deferred Losses On Sale Of Assets [Member]

Southern Natural Gas Company [Member]

Wyoming Interstate Company, L.L.C. (WIC) [Member]

Southern Natural Gas Company [Member]

Wyoming Interstate Company, L.L.C. (WIC) [Member]

Regulatory Assets and Liabilities Disclosure [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory assets recovery period

'

'

'

'

'

'42 years

'1 year

'3 years

'

'

'

'

Amortization of regulatory asset

$31

'

'

$12

$11

'

'

'

'

'

'

'

Adjustment to CIG postretirement benefit plan

0

2

9

'

'

'

'

'

'

'

'

'

Rate Proceedings [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Rate case settlement revenues reduction in 2013

'

'

'

'

'

'

'

'

11

4

'

'

Rate case settlement additional revenues reduction in 2014

'

'

'

'

'

'

'

'

23

'

'

12

Rate case settlement additional revenues reduction in 2015

'

'

'

'

'

'

'

'

'

'

2

'

Rate case settlement additional revenues reduction in 2016

'

'

'

'

'

'

'

'

'

'

$12

'

Transactions_with_Major_Custom2

Transactions with Major Customers (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of revenues from major customers	'	'	'
Revenues	$1,505	$1,515	$1,531
Shell Oil Company and subsidiaries [Member]	'	'	'
Summary of revenues from major customers	'	'	'
Revenues	220	220	221
PSCo and subsidiary [Member]	'	'	'
Summary of revenues from major customers	'	'	'
Revenues	170	169	170
AGL Resources and subsidiaries [Member]	'	'	'
Summary of revenues from major customers	'	'	'
Revenues	$155	$161	$163

Transactions_with_Major_Custom3

Transactions with Major Customers (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Transactions with Major Customers [Abstract]	'	'	'
Non-affiliate trade accounts receivable	$143	$148	'
Other non-affiliate accounts receivable	1	0	'
Percentage of operating revenues	10.00%	'	'
Revenue, Major Customer [Line Items]	'	'	'
Annual firm revenue	1,505	1,515	1,531
High Plains through 2029 [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Annual firm revenue	39	'	'
Totem through 2040 [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Annual firm revenue	$39	'	'

Accounts_Receivable_Sales_Prog1

Accounts Receivable Sales Programs (Details Textuals) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 20, 2012	Dec. 31, 2012
Summary of accounts receivable sales program	'	'
Amounts paid to terminate accounts receivable sales program	$44	'
Accounts receivable sold to the third-party financial institution	418	'
Period of settlement of short term assets	'60 days	'
Cash received for accounts receivable sold under the programs	242	'
Deferred purchase price related to accounts receivable sold	176	'
Cash received related to the deferred purchase price	191	'
Outstanding deferred purchase price	'	$0