Targa Resources Partners (NGLS-PA) 10-K 17 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Jun. 30, 2014	Feb. 06, 2015
Document and Entity Information [Line Items]
Entity Registrant Name	Targa Resources Partners LP
Entity Central Index Key	1379661
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$6,669
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Common Units [Member]
Document and Entity Information [Line Items]
Entity Common Stock, Shares Outstanding			118,880,758
General Partner Units [Member]
Document and Entity Information [Line Items]
Entity Common Stock, Shares Outstanding			2,426,139

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$72.30		$57.50
Trade receivables, net of allowances of $0.0 million and $0.9 million	566.8		658.6
Inventories	168.9		150.7
Assets from risk management activities	44.4		2
Other current assets	3.8		7.1
Total current assets	856.2		875.9
Property, plant and equipment	6,514.30		5,751.60
Accumulated depreciation	-1,689.70		-1,406.20
Property, plant and equipment, net	4,824.60		4,345.40
Intangible assets, net	591.9		653.4
Long-term assets from risk management activities	15.8		3.1
Investment in unconsolidated affiliate	50.2		55.9
Other long-term assets	38.5		37.7
Total assets	6,377.20	[1]	5,971.40
Current liabilities:
Accounts payable and accrued liabilities	592.7		721.2
Accounts payable to Targa Resources Corp.	53.2		52.4
Accounts receivable securitization facility	182.8		0
Liabilities from risk management activities	5.2		8
Total current liabilities	833.9		781.6
Long-term debt	2,783.40		2,905.30
Long-term liabilities from risk management activities	0		1.4
Deferred income taxes	13.7		12.1
Other long-term liabilities	57.8		52.6
Commitments and contingencies (see Notes 16 and 17)
Owners' equity
Limited partners	2,384.10		2,001.90
General partner	78.6		62
Receivables from unit issuances	-1		0
Accumulated other comprehensive income (loss)	60.3		-6.1
Treasury units at cost (66,742 units as of December 31, 2014, and 0 as of December 31, 2013)	-4.8		0
Partners' Capital	2,517.20		2,057.80
Noncontrolling interests in subsidiaries	171.2		160.6
Total owners' equity	2,688.40		2,218.40
Total liabilities and owners' equity	$6,377.20		$5,971.40
[1]	Corporate assets primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our long-term debt.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Current assets:
Allwance for receivables	$0	$0.90
Owners' equity
Limited partners common units issued (in units)	118,652,798	111,263,207
Limited partners common units outstanding (in units)	118,586,056	111,263,207
General partner units issued (in units)	2,420,124	2,270,680
General partner units outstanding (in units)	2,420,124	2,270,680
Treasury units at cost (in units)	66,742	0

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract]
Revenues	$8,616.50		$6,314.90		$5,676.90
Costs and expenses:
Product purchases	7,046.90		5,137.20		4,672.20
Operating expenses	433		376.2		313
Depreciation and amortization expenses	346.5		271.6		197.3
General and administrative expenses	139.8		143.1		131.6
Other operating (income) expense	-3		9.6		19.9
Income from operations	653.3		377.2		342.9
Other income (expense):
Interest expense, net	-143.8		-131		-116.8
Equity earnings	18		14.8		1.9
Gain (loss) on debt redemptions and amendments	-12.4		-14.7		-12.8
Other	-5.2		15.2		-7.8
Income before income taxes	509.9		261.5		207.4
Income tax (expense) benefit:
Current	-3.2		-2		-2.5
Deferred	-1.6		-0.9		-1.7
Total income tax benefit (expense)	-4.8		-2.9		-4.2
Net income	505.1		258.6		203.2
Less: Net income attributable to noncontrolling interests	37.4		25.1		28.6
Net income attributable to Targa Resources Partners LP	467.7		233.5		174.6
Net income attributable to general partner	148.7		107.5		66.7
Net income attributable to limited partners	319		126		107.9
Net income attributable to Targa Resources Partners LP	$467.70		$233.50		$174.60
Net income per limited partner unit - basic (in dollars per share)	$2.78		$1.19		$1.20
Net income per limited partner unit - diluted (in dollars per share)	$2.77		$1.19		$1.20
Weighted average units outstanding - basic (in shares)	114.7		105.5		90.1
Weighted average limited partner units outstanding - diluted (in shares)	115.1	[1]	105.7	[1]	90.2	[1]
[1]	For the year ended December 31, 2014, approximately 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net income	$505.10	$258.60	$203.20
Commodity hedging contracts:
Change in fair value	59.8	-5.8	76.4
Settlements reclassified to revenues	4.2	-21.2	-43.9
Interest rate swaps:
Settlements reclassified to interest expense, net	2.4	6.1	7.9
Other comprehensive income (loss)	66.4	-20.9	40.4
Comprehensive income (loss)	571.5	237.7	243.6
Less: Comprehensive income attributable to noncontrolling interests	37.4	25.1	28.6
Comprehensive income attributable to Targa Resources Partners LP	$534.10	$212.60	$215

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (USD $)	Limited Partners Common [Member]	General Partner [Member]	Receivables from Unit Issuances [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Units [Member]	Non-controlling Interests [Member]	Total
In Millions, except Share data, unless otherwise specified
Balance at Dec. 31, 2011	$1,221.20	$27.20	$0	($25.60)	$0	$138.90	$1,361.70
Balance (in units) at Dec. 31, 2011	84,756,000	1,730,000			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	3.6	0	0	0	0	0	3.6
Compensation on equity grants (in units)	0				0
Accrual of distribution equivalent rights	-0.5	0	0	0	0	0	-0.5
Issuance of common units under compensation program	0	0	0	0	0	0	0
Issuance of common units under compensation program (in units)	10,000	0			0
Equity offerings	543	0	0	0	0	0	543
Equity offerings (in units)	15,330,000	0			0
Contributions from Targa Resources Corp.	0	11.5	0	0	0	0	11.5
Contributions from Targa Resources Corp. (in units)	0	313,000			0
Distributions to noncontrolling interests	0	0	0	0	0	-20.2	-20.2
Contribution from noncontrolling interests	0	0	0	0	0	3.2	3.2
Other comprehensive income (loss)	0	0	0	40.4	0	0	40.4
Net income	107.9	66.7	0	0	0	28.6	203.2
Distributions	-225.7	-60.1	0	0	0	0	-285.8
Balance at Dec. 31, 2012	1,649.50	45.3	0	14.8	0	150.5	1,860.10
Balance (in units) at Dec. 31, 2012	100,096,000	2,043,000			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	6	0	0	0	0	0	6
Compensation on equity grants (in units)	0	0			0
Accrual of distribution equivalent rights	-1.7	0	0	0	0	0	-1.7
Issuance of common units under compensation program	0	0	0	0	0	0	0
Issuance of common units under compensation program (in units)	13,000	0			0
Equity offerings	517.8	0	0	0	0	0	517.8
Equity offerings (in units)	11,154,000	0			0
Contributions from Targa Resources Corp.	0	10.8	0	0	0	0	10.8
Contributions from Targa Resources Corp. (in units)	0	228,000			0
Distributions to noncontrolling interests	0	0	0	0	0	-19.3	-19.3
Contribution from noncontrolling interests	0	0	0	0	0	4.3	4.3
Other comprehensive income (loss)	0	0	0	-20.9	0	0	-20.9
Net income	126	107.5	0	0	0	25.1	258.6
Distributions	-295.7	-101.6	0	0	0	0	-397.3
Balance at Dec. 31, 2013	2,001.90	62	0	-6.1	0	160.6	2,218.40
Balance (in units) at Dec. 31, 2013	111,263,000	2,271,000			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	9.2	0	0	0	0	0	9.2
Compensation on equity grants (in units)	0	0			0
Accrual of distribution equivalent rights	-1.4	0	0	0	0	0	-1.4
Issuance of common units under compensation program	0	0	0	0	0	0	0
Issuance of common units under compensation program (in units)	215,000	0			0
Units tendered for tax withholding obligations	0	0	0	0	-4.8	0	-4.8
Units tendered for tax withholding obligations (in units)	-67,000	0			67,000
Equity offerings	408.4	0	0	0	0	0	408.4
Equity offerings (in units)	7,175,000	0			0
Contributions from Targa Resources Corp.	0	8.7	-1	0	0	0	7.7
Contributions from Targa Resources Corp. (in units)	0	149,000			0
Distributions to noncontrolling interests	0	0	0	0	0	-26.8	-26.8
Other comprehensive income (loss)	0	0	0	66.4	0	0	66.4
Net income	319	148.7	0	0	0	37.4	505.1
Distributions	-353	-140.8	0	0	0	0	-493.8
Balance at Dec. 31, 2014	$2,384.10	$78.60	($1)	$60.30	($4.80)	$171.20	$2,688.40
Balance (in units) at Dec. 31, 2014	118,586,000	2,420,000			67,000

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income	$505.10	$258.60	$203.20
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense	11.2	15.5	17.6
Compensation on equity grants	9.2	6	3.6
Depreciation and other amortization expense	346.5	271.6	197.3
Accretion of asset retirement obligations	4.4	3.9	3.9
Deferred income tax expense (benefit)	1.6	0.9	1.7
Equity earnings of unconsolidated affiliate	-18	-14.8	-1.9
Distributions of unconsolidated affiliate	18	12	1.9
Risk management activities	4.7	-0.5	5.3
(Gain) loss on sale or disposition of assets	-4.8	3.9	15.6
(Gain) loss on debt redemptions and amendments	12.4	14.7	12.8
Changes in operating assets and liabilities:
Receivables and other assets	94.5	-145.8	90.2
Inventory	-35.9	-84.5	5.9
Accounts payable and other liabilities	-110.4	69.9	-91.7
Net cash provided by operating activities	838.5	411.4	465.4
Cash flows from investing activities
Outlays for property, plant and equipment	-762.2	-1,013.60	-582.3
Business acquisitions, net of cash acquired	0	0	-996.2
Investment in unconsolidated affiliate	0	0	-16.8
Return of capital from unconsolidated affiliate	5.7	0	0.5
Other, net	5.1	-12.7	1
Net cash used in investing activities	-751.4	-1,026.30	-1,593.80
Cash flows from financing activities
Proceeds from borrowings under credit facility	1,600	1,613	1,595
Repayments of credit facility	-1,995	-1,838	-1,473
Redemption of senior notes	-259.8	-183.2	-217.7
Issuance of senior notes	800	625	1,000
Proceeds from accounts receivable securitization facility	381.9	373.3	0
Repayments of accounts receivable securitization facility	-478.8	-93.6	0
Costs paid in connection with financing arrangements	-14	-15.3	-35.7
Proceeds from equity offerings and general partner contributions	420.4	535.5	575
Repurchase of common units under compensation plans	-4.8	0	0
Distributions paid to unit holders	-495.4	-397.3	-285.7
Contributions received from parent	0	0	1
Contributions received from noncontrolling interests	0	4.3	3.2
Distributions paid to noncontrolling interests	-26.8	-19.3	-21.3
Net cash provided by (used in) financing activities	-72.3	604.4	1,140.80
Net change in cash and cash equivalents	14.8	-10.5	12.4
Cash and cash equivalents, beginning of period	57.5	68	55.6
Cash and cash equivalents, end of period	$72.30	$57.50	$68

Organization_and_Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2014
Organization and Operations [Abstract]
Organization and Operations	Note 1 — Organization and Operations
	Our Organization
	Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
	Targa Resources GP LLC is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa. As of December 31, 2014, Targa owned a 12.7% interest in us in the form of 2,420,124 general partner units and 12,945,659 common units. In addition, Targa Resources GP LLC also owns incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48% of distributable cash for a quarter.
	Allocation of costs
	The employees supporting our operations are employed by Targa Resources LLC, a Delaware limited liability company and an indirect wholly owned subsidiary of Targa. Our financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa centralized general and administrative services.
	Our Operations
	We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 22 for certain financial information for our business segments.

Basis_of_Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Basis of Presentation [Abstract]
Basis of Presentation	Note 2 — Basis of Presentation
	Revision of Previously Reported Revenues and Product Purchases
	During the third quarter of 2014, we concluded that certain prior period buy-sell transactions related to the marketing of NGL products were incorrectly reported on a gross basis as Revenues and Product Purchases in previous Consolidated Statements of Operations. GAAP requires that such transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another be reported as a single transaction on a combined net basis.
	We concluded that these misclassifications were not material to any of the periods affected. However, we have revised previously reported revenues and product purchases to correctly report NGL buy-sell transactions on a net basis. Accordingly, Revenues and Product Purchases reported in our Form 10-K filed on February 14, 2014 have been reduced by equal amounts as presented in the following tables. There is no impact on previously reported net income, cash flows, financial position or other profitability measures.
		Year Ended December 31,
		2013			2012
	As Reported:
	Revenues	$	6,556.20		$	5,883.60
	Product Purchases		5,378.50			4,878.90
	Effect of Revisions:
	Revenues		(241.3	)		(206.7	)
	Product Purchases		(241.3	)		(206.7	)
	As Revised:
	Revenues		6,314.90			5,676.90
	Product Purchases		5,137.20			4,672.20

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Significant Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies
	Consolidation Policy
	Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
	We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.
	Cash and Cash Equivalents
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
	Comprehensive Income
	Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as hedges.
	Allowance for Doubtful Accounts
	Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
	Inventories
	Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment.  Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method.
	Product Exchanges
	Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.
	Gas Processing Imbalances
	Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
	Derivative Instruments
	We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives.
	If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
	If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues.
	We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
	The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period.
	We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
	For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis and report the related fair value on a gross basis.
	Property, Plant and Equipment
	Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
	Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
	Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
	We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
	Intangible Assets
	Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers.
	Asset Retirement Obligations (“AROs”)
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing.
	Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.
	Debt Issue Costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
	Accounts Receivable Securitization Facility
	Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows.
	Environmental Liabilities and Other Loss Contingencies
	Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.
	Income Taxes
	We generally are not subject to federal income taxes.   For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners.  The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the consolidated statement of income.  We are also subject to the Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.
	Noncontrolling Interests
	Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of the balance sheet. In the statements of operations and statements of comprehensive income, noncontrolling interests reflects the attribution of results to third-party investors.
	Revenue Recognition
	Our operating revenues are primarily derived from the following activities:
		•	sales of natural gas, NGLs, condensate, crude oil and petroleum products;
		•	services related to compressing, gathering, treating, and processing of natural gas; and
		•	services related to NGL fractionation, terminaling and storage, transportation and treating.
	We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
	For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above.
	We generally report sales revenues gross in our consolidated statements of operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis.
	Unit-Based Compensation
	We award unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award.
	Earnings per Unit
	We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU.
	The limited partners’ net income per unit is based on net income after allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period.
	Use of Estimates
	When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
	Recent Accounting Pronouncements
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2014, limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have, or will have, a major effect on operations and financial results.  The amendment requires expanded disclosures for discontinued operations and also requires additional disclosures regarding disposals of individually significant components that do not qualify as discontinued operations. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five-step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
	The revenue recognition standard will be effective for us starting in the first quarter of 2017. Early adoption is not permitted. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in our first quarter report in 2017. We have commenced our analysis of the new standard and its impact on our revenue recognition practices.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendment is effective for the annual period beginning after December 15, 2016, and for annual and interim periods thereafter, with early adoption permitted. The amendment requires an entity’s management to evaluate for each annual and interim reporting period whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued.  If substantial doubt is raised, further analysis and disclosures are required, including management’s plans to mitigate the adverse conditions or events.
In November 2014, FASB issued ASU No. 2014-17, Business Combinations (Topic 805): Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force), with an effective date of November 18, 2014. The amendment provides an acquired entity the option to apply push-down accounting in its separate financial statements when a change-in-control event occurs.

Business_Acquisitions

Business Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Acquisitions [Abstract]
Business Acquisitions	Note 4 –Business Acquisitions
	2012 Acquisition
	Badlands
	On December 31, 2012, we completed the acquisition of Saddle Butte Pipeline, LLC’s ownership of its Williston Basin crude oil pipeline and terminal system and its natural gas gathering and processing operations (collectively “Badlands”), for cash consideration of $975.8 million, subject to a contingent payment.
	The acquired business, located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota, expands our portfolio of midstream assets and diversifies our business with the addition of fee-based crude oil gathering and natural gas gathering and processing. The Badlands financial results are included in our Field Gathering and Processing business segment.
	Pursuant to the Membership Interest Purchase and Sale Agreement (“MIPSA”), the acquisition was subject to a contingent payment of $50 million (the “contingent consideration”) if aggregate crude oil gathering volumes exceeded certain stipulated monthly thresholds during the period from January 2013 through June 2014. If the threshold was not attained during the contingency period, no payment is owed. Accounting standards require that the contingent consideration be recorded at fair value at the date of acquisition and revalued at subsequent reporting dates under the acquisition method of accounting. At December 31, 2012, we recorded a $15.3 million accrued liability representing the fair value of this contingent consideration, determined by a probability based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA.
	Changes in the fair value of this accrued liability were included in earnings and reported as Other income (expense) in the Consolidated Statements of Operations. During 2013, the contingent consideration was re-estimated to be $0, resulting in an increase in Other income of $15.3 million in 2013. The contingent period expired June 2014, with no payment required.
	The following table summarizes the consideration paid for the Badlands acquisition and the determination of the assets and liabilities acquired at the December 31, 2012 acquisition date.
			31-Dec-12
	Cash		$	975.8
	Contingent consideration			15.3
	Total consideration		$	991.1
	Assets acquired and liabilities assumed
	Financial assets		$	35.4
	Inventory			16.2
	Property, plant and equipment			295.3
	Intangible assets			679.6
	Financial liabilities			(35.4	)
	Total net assets		$	991.1
	Intangible assets consist of customer contracts and relationships acquired in the Badlands acquisition. Using relevant information and assumptions, the fair value of acquired identifiable intangible assets at the date of acquisition was determined. Fair value is generally calculated as the present value of estimated future cash flows. Key assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. See Note 6 for details of the amortization method for intangible assets.
	Pro Forma Results
	As the Badlands acquisition was completed on December 31, 2012, there were no results of operations attributable to this acquisition for 2012. In 2012, we incurred $6.1 million of acquisition-related costs associated with the Badlands acquisition (included in Other expense in our Consolidated Statements of Operations).
	The following table shows the unaudited pro forma consolidated results of operations for the year ended 2012.
			Year Ended December 31, 2012
			(In millions, except per unit amounts)
	Revenues		$	5,907.80
	Net income			157.4
	Net income attributable to limited partners			63.1
	Net income per limited partner unit - Basic and diluted		$	0.63
	The pro forma consolidated results of operations include adjustments to include the reported results of the acquired company for 2012, as adjusted to:
		·	exclude the financial results of assets retained by the seller;
		·	report revenues from the purchase and sale of crude oil inventory with the same counterparty on a net basis to conform to our accounting policy;
		·	report revenues from the purchases and sales of certain Badlands natural gas processing agreements in which we are in substance an agent rather than a principal on a net basis;
		·	include the incremental depreciation expenses associated with the fair value adjustments to property, plant and equipment as a result of applying the acquisition method of accounting (assumed straight-line method over useful lives of 15-20 years);
		·	include the amortization expense associated with the fair value adjustments to definite-lived intangibles in a manner that follows the expected pattern of services provided to customers, over a useful life of 20 years;
		·	include the financing costs associated with the debt offering and borrowings under our Senior Second Credit Facility (the “TRP Revolver”)  used to fund a portion of the acquisition;
		·	adjust the attribution of net income to general partners and limited partners, and the calculation of weighted average basic and diluted units to give effect to the equity offering used to fund a portion of the acquisition; and
		·	exclude $6.1 million of acquisition costs incurred in 2012 that were directly related to the transaction.
	The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
	Pending Atlas Mergers
	On October 13, 2014, we and Targa announced two proposed merger transactions which would result in our acquisition of Atlas Pipeline Partners, L.P (APL) and the Targa acquisition of Atlas Energy, L.P. (ATLS), a Delaware limited partnership which owns the APL general partner. Upon consummation of these mergers, Targa would relinquish all APL ownership interests and merge the APL general partner into us. Each of the Transactions is contingent on one another, and the Transactions are expected to close concurrently on February 28, 2015, subject to the approval of Targa’s stock issuance in connection with the ATLS Merger by Targa’s stockholders and the approval of the Atlas Mergers by unitholders of ATLS and APL, as applicable, and other customary closing conditions.
	APL Merger
	APL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas. The proposed merger:
	The proposed merger:
		·	adds APL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing Permian, Bakken, Barnett, and Louisiana Gulf Coast operations; and
		·	creates a combined position across the Permian Basin that enhances service capabilities in one of the most active producing basins in North America, with a combined 1,439 MMcf/d of processing capacity and 10,300 miles of pipelines.
	As merger consideration for the APL Merger, holders of APL common units (other than certain common units held by the Partnership or APL or their wholly owned subsidiaries, which will be cancelled) will be entitled to receive 0.5846 of our common units and a one-time cash payment of $1.26 for each APL common unit. The Partnership will also redeem APL’s Class E Preferred Units for an aggregate amount of $126.5 million in cash. As of February 5, 2015 the total APL merger consideration would be valued at $5.0 billion. The portion of the merger consideration represented by our common units will fluctuate in value until the closing date as a result of fluctuations in the market price of our common units.
	In connection with the APL Merger, Targa has agreed to reduce its incentive distribution rights for the four years following closing by fixed amounts of $37.5 million, $25.0 million, $10.0 million and $5.0 million, respectively. These annual amounts will be applied in equal quarterly installments for each successive four quarter period following closing.
	ATLS Merger
	ATLS holds the general partner’s interest in APL as well as Incentive Distribution Rights and 5.5% limited partner interest. Under the terms of the ATLS Merger, each existing holder of common units of ATLS, after giving effect to the spin-off of non-APL businesses, will be entitled to receive a cash payment of $9.12 and 0.1809 of Targa common shares for each ATLS common unit. This equates to 10.35 million shares of Targa common stock and $522 million in cash payments. Additionally, Targa will provide ATLS with $88 million of cash for the repayment of a portion of the ATLS outstanding indebtedness and fund approximately $190 million related to change of control payments payable by ATLS. As of February 5, 2015 the total ATLS merger consideration would be valued at $1.6 billion. The portion of the merger consideration represented by Targa’s common shares will fluctuate in value until the closing date as a result of fluctuations in the market price of our common shares.
	Pre-Closing Merger Financing Activities
	In January 2015, we commenced cash tender offers for any and all of the outstanding APL Senior Notes. These tender offers are in connection with, and conditioned upon, the consummation of the proposed merger with APL. The proposed merger with APL, however, is not conditioned on the consummation of the tender offers. Each tender offer is scheduled to expire on February 18, 2015, unless extended by us at our sole discretion.
	Under the terms of the tender offer, APL noteholders will receive $1,015 per $1,000 principal if tendered before January 29, 2015 and $985 per $1,000 principal if tendered after that date. Holders of tendered APL Notes will also receive accrued and unpaid interest from the most recent interest payment date on their series of APL Notes.
	The outstanding APL Senior Notes consist of:
	APL Senior Notes		Amount tendered as of
			6-Feb-15
	$500 million 6⅝ due 2020		Less than majority
	$400 million 4¾ due 2021			98.3	%
	$650 million 5⅞% due 2023			91.6	%
	The consummation of the merger with APL will result in a Change of Control under the APL Indenture and obligate the APL Issuers to make a Change of Control Offer at $1,010 for each $1,000 principal plus accrued and unpaid interest from the most recent interest payment date. As permitted by the APL Indenture, we are making a Change of Control Offer for any and all of the 2020 APL Notes in lieu of the APL Issuers and in advance of, and conditioned upon, the consummation of the merger with APL. The merger, however, is not conditioned on the consummation of the Change of Control Offer. The Change of Control Offer is also being made independently of the tender offers for the APL Notes. The Change of Control Offer is scheduled to expire on March 3, 2015, unless extended by us. Any 2020 APL Notes that remain outstanding after consummation of the Change of Control Offer will continue to be the obligation of the APL Issuers under the governing indenture.
	In January 2015, we privately placed $1.1 billion in aggregate principal amount of 5% Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,090.8 million of net proceeds, which will be used together with borrowings from the TRP Revolver, to fund the cash portion of the APL Merger, the APL Notes Tender Offers and the change of control offers for the 2020 APL Notes.
	Targa Pre-Closing Merger Financing Activities
	Targa has arranged committed financing of $1.1 billion to replace its existing revolving credit facility and to fund the cash components of the ATLS Merger, including cash merger consideration and approximately $190 million related to change of control payments payable by ATLS and transaction fees and expenses. In January 2015, as part of a new senior secured credit facility to syndicate the $1.1 billion in committed financing, Targa announced the launch of a $430 million senior secured term loan maturing 7 years after closing. Targa intends to use the net proceeds from the term loan issuance, in conjunction with a $670 million revolving credit facility maturing 5 years after closing, to fund the cash components of the pending ATLS Merger. These facilities are subject to the closing of the pending Atlas Mergers and market conditions.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Inventories	Note 5 — Inventories
		31-Dec-14		31-Dec-13
	Commodities	$	157.4	$	136.4
	Materials and supplies		11.5		14.3
		$	168.9	$	150.7

Property_Plant_and_Equipment_a

Property, Plant and Equipment and Intangible Assets	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment and Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	Note 6 — Property, Plant and Equipment and Intangible Assets
		31-Dec-14			31-Dec-13			Estimated useful life
								(In years)
	Gathering systems	$	2,588.60		$	2,230.10		5 to 20
	Processing and fractionation facilities		1,884.10			1,598.00		5 to 25
	Terminaling and storage facilities		1,038.90			715.2		5 to 25
	Transportation assets		359			294.7		10 to 25
	Other property, plant and equipment		149.1			121.3		3 to 25
	Land		95.6			89.5			-
	Construction in progress		399			702.8			-
	Property, plant and equipment		6,514.30			5,751.60
	Accumulated depreciation		(1,689.7	)		(1,406.2	)
	Property, plant and equipment, net	$	4,824.60		$	4,345.40
	Intangible assets	$	681.8		$	681.8			20
	Accumulated amortization		(89.9	)		(28.4	)
	Intangible assets, net	$	591.9		$	653.4
	Intangible assets consist of customer contracts and customer relationships acquired in our Badlands business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.
	Amortization expense attributable to these intangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation. The estimated annual amortization expense for these intangible assets is approximately $80.1 million, $88.3 million, $81.5 million, $67.8 million and $56.8 million for each of years 2015 through 2019.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	Note 7 — Asset Retirement Obligations
	Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities, and are included in our Consolidated Balance Sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:
		2014			2013		2012
	Beginning of period	$	50.5		$	45.2	$	42.3
	Change in cash flow estimate		2.1			1.4		(1.0	)
	Accretion expense		4.4			3.9		3.9
	Retirement of ARO		(0.2	)		-		-
	End of period	$	56.8		$	50.5	$	45.2

Investment_in_Unconsolidated_A

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2014
Investment in Unconsolidated Affiliate [Abstract]
Investment in Unconsolidated Affiliate	Note 8 — Investment in Unconsolidated Affiliate
	The following table shows the activity related to our unconsolidated 38.8% interest in Gulf Coast Fractionators LP (“GCF”).
			2014			2013			2012
	Beginning of period		$	55.9		$	53.1		$	36.7
	Equity earnings			18			14.8			1.9
	Cash distributions (1)			(23.7	)		(12.0	)		(2.3	)
	Cash calls for expansion projects			-			-			16.8
	End of period		$	50.2		$	55.9		$	53.1
	-1	Includes $5.7 million and $0.5 million distributions received in excess of our share of cumulative earnings for the years ended December 31, 2014 and 2012. Such excess distributions are considered a return of capital and are disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts_Payable_and_Accrued_L

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2014
Accounts Payable and Accrued Liabilities [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 — Accounts Payable and Accrued Liabilities
		31-Dec-14		31-Dec-13
	Commodities	$	416.7	$	529.7
	Other goods and services		108.9		124.7
	Interest		37.3		35.9
	Compensation and benefits		1.3		1.3
	Income and other taxes		13.6		10.9
	Other		14.9		18.7
		$	592.7	$	721.2

Debt_Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2014
Debt Obligations [Abstract]
Debt Obligations	Note 10 — Debt Obligations
			31-Dec-14				31-Dec-13
	Current:
	Accounts receivable securitization facility, due December 2015 (1)		$	182.8			$	-
	Long-term:
	Senior secured revolving credit facility, variable rate, due October 2017 (2)			-				395
	Senior unsecured notes, 7⅞% fixed rate, due October 2018 (3)			-				250
	Senior unsecured notes, 6⅞% fixed rate, due February 2021			483.6				483.6
	Unamortized discount			(25.2	)			(28.0	)
	Senior unsecured notes, 6⅜% fixed rate, due August 2022			300				300
	Senior unsecured notes, 5¼% fixed rate, due May 2023			600				600
	Senior unsecured notes, 4¼% fixed rate, due November 2023			625				625
	Senior unsecured notes, 4⅛% fixed rate, due November 2019			800				-
	Accounts receivable securitization facility, due December 2014 (1)			-				279.7
	Total long-term debt			2,783.40				2,905.30
	Total Debt		$	2,966.20			$	2,905.30
	Letters of credit outstanding (1)		$	44.1			$	86.8
	-1	The classification of the Securitization Facility as of December 31, 2014 has changed. The outstanding amounts under the Securitization Facility as of December 31, 2013 were reflected as long-term debt in our Consolidated Balance Sheets because we had the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. As of December 31, 2013, we intended to fund the Securitization Facility’s borrowings either by further extending the termination date of the Securitization Facility or by utilizing the availability under our Senior Secured Revolving Credit Facility. As of December 31, 2014, we intended to fund the Securitization Facility’s borrowings solely through further extensions of the termination date of the Securitization Facility; based on our history of extending the Securitization Facility, most recently through the Third Amendment to the Securitization Facility entered into in December 2014. As a result, all amounts outstanding under the Securitization Facility as of December 31, 2014 are reflected as a current liability in our Consolidated Balance Sheets.
	-2	As of December 31, 2014, availability under our $1.2 billion senior secured revolving credit facility was $1,155.9 million.
	-3	The outstanding balance of the 7⅞% Notes was redeemed in November 2014. See “Senior Unsecured Notes” below.
	The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2014 for the next five years, and in total thereafter:
							Scheduled Maturities of Debt
			Total				2015			2016			2017		2018			2019		After 2019
	Senior secured revolving credit facility		$	-			$	-		$	-		$	-	$	-		$	-	$	-
	Senior unsecured notes			2,808.60				-			-			-		-			800		2,008.60
	Account receivable securitization facility			182.8				182.8			-			-		-			-		-
	Total		$	2,991.40			$	182.8		$	-		$	-	$	-		$	800	$	2,008.60
	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2014:
			Range of Interest Rates Incurred				Weighted Average Interest Rate Incurred
	Senior secured revolving credit facility			1.9% - 4.5	%			2	%
	Accounts receivable securitization facility			0.9	%			0.9	%
	Compliance with Debt Covenants
	As of December 31, 2014, we were in compliance with the covenants contained in our various debt agreements.
	Revolving Credit Agreement
	In October 2012, we entered into a Second Amended and Restated Credit Agreement that amended and replaced our variable rate Senior Secured Credit Facility due July 2015 to provide a variable rate Senior Secured Credit Facility due October 3, 2017. The TRP Revolver increased available commitments to $1.2 billion from $1.1 billion and allows the Partnership to request up to an additional $300.0 million in commitment increases.
	In 2012, we incurred a $1.7 million loss related to a partial write-off of debt issue costs associated with the previous revolver as a result of a change in syndicate members under the new TRP Revolver. The remaining deferred debt issue costs along with the issue costs associated with the October 2012 amendment are amortized on a straight-line basis over the life of the TRP Revolver.
	The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate.  The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The Eurodollar rate is equal to LIBOR rate plus an applicable margin ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
	We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
	The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries.
	The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).
	Senior Unsecured Notes
	In January 2012, we privately placed $400.0 million in aggregate principal amount of our 6⅜% Notes, resulting in approximately $395.5 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes.
	In October 2012, $400.0 million in aggregate principal amount of our 5¼% Notes were issued at 99.5% of the face amount, resulting in gross proceeds of $398.0 million. An additional $200.0 million in aggregate principal amount of our 5¼% Notes were issued in December 2012 at 101.0% of the face amount, resulting in gross proceeds of $202.0 million. Both issuances are treated as a single class of debt securities and have identical terms.
	In November 2012, we redeemed all of the outstanding 8¼% Notes at a redemption price of 104.125% plus accrued interest through the redemption date. The redemption resulted in a premium paid on the redemption of $8.6 million, which is included as a cash outflow from financing activities in the Consolidated Statements of Cash Flows, and a write off of $2.5 million of unamortized debt issue costs.
	In May 2013, we privately placed $625.0 million in aggregate principal amount of 4¼% Notes. The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes.
	In June 2013, we paid $106.4 million plus accrued interest, which included a premium of $6.4 million, to redeem $100.0 million of the outstanding 6⅜% Notes. The redemption resulted in a $7.4 million loss on debt redemption, including the write-off of $1.0 million of unamortized debt issue costs.
	In July 2013, we paid $76.8 million plus accrued interest, which included a premium of $4.1 million, per the terms of the note agreement to redeem the outstanding balance of the 11¼% Notes. The redemption resulted in a $7.4 million loss on debt redemption in the third quarter 2013, including the write-off of $1.0 million of unamortized debt issue costs.
	In October 2014, we privately placed $800.0 million in aggregate principal amount of 4⅛% Senior Notes due 2019 (the “4⅛% Notes”). The 4⅛% Notes resulted in approximately $790.8 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and Securitization Facility and for general partnership purposes.
	In November 2014, we redeemed the outstanding 7⅞% Notes at a price of 103.938% plus accrued interest through the redemption date. The redemption resulted in a $12.4 million loss on redemption for the year ended 2014, consisting of premiums paid of $9.9 million and a non-cash loss to write-off $2.5 million of unamortized debt issue costs.
	The terms of the senior unsecured notes outstanding as of December 31, 2014 were as follows:
	Note Issue		Issue Date		Per Annum Interest Rate				Due Date	Dates Interest Paid
	"6⅞% Notes"		Feb-11			6⅞	%		1-Feb-21	February & August 1st
	"6⅜% Notes"		Jan-12			6⅜	%		1-Aug-22	February & August 1st
	"5¼% Notes"		Oct / Dec 2012			5¼	%		1-May-23	May & November 1st
	"4¼% Notes"		May-13			4¼	%		15-Nov-23	May & November 15th
	"4⅛% Notes"		Oct-14			4⅛	%		15-Nov-19	May & November 15th
	All issues of unsecured senior notes are obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of our assets and our Securitization Facility, which is secured by accounts receivable pledged under the Securitization Facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
	Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by both Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s Corporation (“S&P”) (or rated investment grade by either Moody’s or S&P for the 6⅜% Notes, 5¼% Notes, 4¼% Notes and 4⅛% Notes) and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.
	We may redeem up to 35% of the aggregate principal amount of Notes at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 90 days (180 days for the 6⅜% Notes, 5¼% Notes, 4¼ % Notes and 4⅛% Notes) of the date of the closing of such equity offering.
	Note Issue		Any Date Prior To		Price
	6⅞% Notes		1-Feb-14			106.875	%
	6⅜% Notes		1-Feb-15			106.375	%
	5¼% Notes		1-Nov-15			105.25	%
	4¼% Notes		15-May-16			104.25	%
4⅛% Notes		15-Nov-19			104.125	%
We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
6⅞% Notes						6⅜% Notes						5¼% Notes					4¼% Notes					4⅛% Notes
Redemption Date:						Redemption Date:						Redemption Date:					Redemption Date:					Redemption Date:
1-Feb						1-Feb						1-Nov					15-May					15-Nov
Year		Price				Year			Price			Year		Price			Year		Price			Year		Price
2016			103.438	%			2017			103.188	%		2017		102.625	%		2018		102.125	%		2016		102.063	%
2017			102.292	%			2018			102.125	%		2018		101.75	%		2019		101.417	%		2017		101.031	%
2018			101.146	%			2019			101.063	%		2019		100.875	%		2020		100.708	%	2018 and thereafter			100	%
2019 and thereafter			100	%		2020 and thereafter				100	%	2020 and thereafter			100	%	2021 and thereafter			100	%
Accounts Receivable Securitization Facility
The Securitization Facility provides up to $300.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 11, 2015. Under the Securitization Facility, two of our consolidated subsidiaries (Targa Liquids Marketing and Trade LLC (“TLMT”) and Targa Gas Marketing LLC (“TGM”)) sell or contribute receivables, without recourse, to another of our consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT, TGM or us. Any excess receivables are eligible to satisfy the claims of creditors of TLMT, TGM or us. As of December 31, 2014, total funding under the Securitization Facility was $182.8 million.
April 2013 Shelf
In April 2013, we filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expires in April 2016. There was no activity under the April 2013 Shelf during the years ended December 31, 2014 and 2013.
July 2013 Shelf
In July 2013, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $800.0 million of debt or equity securities (the “July 2013 Shelf”). The July 2013 Shelf expires in August 2016. See Note 11 for equity issuances under the July 2013 Shelf.
Debt Re-acquisitions Summary
The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations:
		2014				2013			2012
Premium over face value paid upon redemption:
6⅜ Notes		$	-			$	6.4		$	-
7⅞ Notes			9.9				-			-
8¼ Notes			-				-			8.6
11¼ Notes			-				4.1			-
Recognition of unamortized discount:
11¼ Notes			-				2.2			-
Write-off of deferred debt issue costs:
6⅜ Notes			-				1			-
7⅞ Notes			2.5				-			-
8¼ Notes			-				-			2.5
11¼ Notes			-				1			-
Partial write-off of TRP Revolver deferred debt issue costs related to 2012 amendment			-				-			1.7
Loss on debt redemptions and amendments		$	12.4			$	14.7		$	12.8
Subsequent Event
In January 2015, we privately placed $1.1 billion in aggregate principal amount of 5% Notes resulting in approximately $1,090.8 million of net proceeds, which will be used together with borrowings from the TRP Revolver, to fund the APL Note tender offers and, if applicable, the change of control offers for the APL Notes pursuant to the indentures governing the APL Notes.

Partnership_Units_and_Related_

Partnership Units and Related Matters	12 Months Ended
	Dec. 31, 2014
Partnership Units and Related Matters [Abstract]
Partnership Units and Related Matters	Note 11 — Partnership Units and Related Matters
	Public Offerings of Common Units
	In 2010, we filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provided us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The 2010 Shelf expired in April 2013. The following transactions were completed in 2012.
		·	January 2012 – 4,405,000 common units (including underwriters’ overallotment option) at a price of $38.30 per common unit, providing net proceeds of $164.8 million. As part of this offering, Targa purchased 1,300,000 common units with an aggregate value of $49.8 million. In addition, Targa contributed $3.5 million to maintain its 2% general partner interest. We used the net proceeds from this offering for general partnership purposes, including the repayment of indebtedness.
		·	November 2012 – 10,925,000 common units (including underwriters’ overallotment option) at a price of $36.00 per common unit, providing net proceeds of $378.2 million. Targa contributed $8.0 million to maintain its 2% general partner interest. We used the net proceeds from this offering to fund a portion of the $975.8 million purchase price of the Badlands acquisition.
	In July 2012, we filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $300.0 million of debt or equity securities (the “2012 Shelf”). The 2012 Shelf expires in August 2015.
	In August 2012, we entered into an Equity Distribution Agreement (the “2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which we may sell, at our option, up to an aggregate of $100.0 million of our common units through Citigroup, as sales agent, under the 2012 Shelf. During the year ended December 31, 2013, we issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. Targa contributed $2.0 million to us to maintain its 2% general partner interest.
	In March 2013, we entered into a second Equity Distribution Agreement under the 2012 Shelf (the “March 2013 EDA”) with Citigroup, Deutsche Bank Securities Inc. (“Deutsche Bank”), Raymond James & Associates, Inc. (“Raymond James”) and UBS Securities LLC (“UBS”), as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $200.0 million of our common units. During the year ended December 31, 2013 we issued 4,204,751 common units receiving net proceeds of $197.5 million. Targa contributed $4.1 million to maintain its 2% general partner interest.
	In August 2013, we entered into an Equity Distribution Agreement under the July 2013 Shelf (the “August 2013 EDA”) with Citigroup, Deutsche Bank, Morgan Stanley & Co. LLC, Raymond James, RBC Capital Markets, LLC, UBS and Wells Fargo Securities, LLC, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400.0 million of our common units. During the year ended 2013, we issued 4,259,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million. Targa contributed $4.7 million to us to maintain its 2% general partner interest.
	In May 2014, we entered into an additional equity distribution agreement under our July 2013 Shelf (the “May 2014 EDA”), with Barclays Capital Inc., Citigroup, Deutsche Bank, Jefferies LLC, Morgan Stanley & Co. LLC, Raymond James, RBC Capital Markets, LLC, UBS and Wells Fargo Securities, LLC, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400 million of our common units.
	During the year ended  2014, pursuant to the August 2013 EDA and the May 2014 EDA, we issued a total of 7,175,096 common units representing total net proceeds of $408.4 million, (net of commissions up to 1% of gross proceeds to our sales agent), which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $8.4 million to us to maintain its 2% general partner interest, of which $1.0 million was settled in January 2015.
	Subsequent Event
	In January 2015, we issued 284,137 common units and received proceeds of $13.0 million, net of commissions and fees, pursuant to the May 2014 EDA. Targa contributed $0.3 million to maintain its 2% general partner interest.
	Distributions
	In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by us during the periods presented.
				Distributions
				Limited		General Partner						Distributions
				Partners								per Limited
	Three Months Ended		Date Paid or to be Paid	Common		Incentive		2%		Total		Partner Unit
				(In millions, except per unit amounts)
	2014
	31-Dec-14		13-Feb-15	$	96.3	$	38.4	$	2.7	$	137.4	$	0.81
	30-Sep-14		14-Nov-14		92.3		36		2.6		130.9		0.7975
	30-Jun-14		14-Aug-14		89.5		33.7		2.5		125.7		0.78
	31-Mar-14		15-May-14		87.2		31.7		2.4		121.3		0.7625
	2013
	31-Dec-13		14-Feb-14		84		29.5		2.3		115.8		0.7475
	30-Sep-13		14-Nov-13		79.4		26.9		2.2		108.5		0.7325
	30-Jun-13		14-Aug-13		75.8		24.6		2		102.4		0.715
	31-Mar-13		15-May-13		71.7		22.1		1.9		95.7		0.6975
	2012
	31-Dec-12		14-Feb-13		69		20.1		1.8		90.9		0.68
	30-Sep-12		14-Nov-12		59.1		16.1		1.5		76.7		0.6625
	30-Jun-12		14-Aug-12		57.3		14.4		1.5		73.2		0.6425
	31-Mar-12		15-May-12		55.5		12.7		1.4		69.6		0.6225

Earnings_per_Limited_Partner_U

Earnings per Limited Partner Unit	12 Months Ended
	Dec. 31, 2014
Earnings per Limited Partner Unit [Abstract]
Earnings per Limited Partner Unit	Note 12 — Earnings per Limited Partner Unit
	The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per limited partner unit:
		2014		2013		2012
	Net income	$	505.1	$	258.6	$	203.2
	Less: Net income attributable to noncontrolling interests		37.4		25.1		28.6
	Net income attributable to Targa Resources Partners LP	$	467.7	$	233.5	$	174.6
	Net income attributable to general partner	$	148.7	$	107.5	$	66.7
	Net income attributable to limited partners		319		126		107.9
	Net income attributable to Targa Resources Partners LP	$	467.7	$	233.5	$	174.6
	Weighted average units outstanding - basic		114.7		105.5		90.1
	Net income available per limited partner unit - basic	$	2.78	$	1.19	$	1.2
	Weighted average units outstanding		114.7		105.5		90.1
	Dilutive effect of unvested stock awards		0.4		0.2		0.1
	Weighted average units outstanding - diluted (1)		115.1		105.7		90.2
	Net income available per limited partner unit - diluted	$	2.77	$	1.19	$	1.2
	(1) For the year ended December 31, 2014, approximately 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities [Abstract]
Derivative Instruments and Hedging Activities	Note 13 — Derivative Instruments and Hedging Activities
	Commodity Hedges
	The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Field Gathering and Processing segment and the LOU business unit in our Coastal Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.
	The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations, which closely approximate our actual natural gas and NGL delivery points.
	We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the New York Mercantile Exchange (“NYMEX”) futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes. Hedge ineffectiveness was immaterial for all periods presented.
	At December 31, 2014, the notional volumes of our commodity hedges for equity volumes were:
	Commodity		Instrument		Unit		2015				2016				2017
	Natural Gas		Swaps		MMBtu/d			55,551				30,500				5,000
	NGL		Swaps		Bbl/d			1,210				-				-
	Condensate		Swaps		Bbl/d			1,500				1,000				500
	We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and we record changes in fair value and cash settlements to revenues.
	Our derivative contracts are subject to netting arrangements that allow net cash settlement of offsetting asset and liability positions with the same counterparty. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
				Fair Value as of December 31, 2014								Fair Value as of December 31, 2013
		Balance Sheet		Derivative				Derivative				Derivative				Derivative
		Location		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as hedging instruments
	Commodity contracts	Current		$	44.4			$	-			$	2			$	7.7
	Long-term				15.8				-				3.1				1.4
	Total derivatives designated as hedging instruments			$	60.2			$	-			$	5.1			$	9.1
	Derivatives not designated as hedging instruments
	Commodity contracts	Current		$	-			$	5.2			$	-			$	0.3
	Total derivatives not designated as hedging instruments			$	-			$	5.2			$	-			$	0.3
	Total current position			$	44.4			$	5.2			$	2			$	8
	Total long-term position				15.8				-				3.1				1.4
	Total derivatives			$	60.2			$	5.2			$	5.1			$	9.4
	The pro forma impact of reporting derivatives in the Consolidated Balance Sheets on a net basis is as follows:
			Gross Presentation								Pro forma Net Presentation
			Asset				Liability				Asset				Liability
	31-Dec-14		Position				Position				Position				Position
	Current position
	Counterparties with offsetting position		$	35.5			$	4.4			$	31.1			$	-
	Counterparties without offsetting position - assets			8.9				-				8.9				-
	Counterparties without offsetting position - liabilities			-				0.8				-				0.8
				44.4				5.2				40				0.8
	Long-term position
	Counterparties with offsetting position			-				-				-				-
	Counterparties without offsetting position - assets			15.8				-				15.8				-
	Counterparties without offsetting position - liabilities			-				-				-				-
				15.8				-				15.8				-
	Total derivatives
	Counterparties with offsetting position			35.5				4.4				31.1				-
	Counterparties without offsetting position - assets			24.7				-				24.7				-
	Counterparties without offsetting position - liabilities			-				0.8				-				0.8
			$	60.2			$	5.2			$	55.8			$	0.8
	31-Dec-13
	Current position
	Counterparties with offsetting position		$	1.9			$	4.4			$	-			$	2.5
	Counterparties without offsetting position - assets			0.1				-				0.1				-
	Counterparties without offsetting position - liabilities			-				3.6				-				3.6
				2				8				0.1				6.1
	Long-term position
	Counterparties with offsetting position			0.7				1.2				-				0.5
	Counterparties without offsetting position - assets			2.4				-				2.4				-
	Counterparties without offsetting position - liabilities			-				0.2				-				0.2
				3.1				1.4				2.4				0.7
	Total derivatives
	Counterparties with offsetting position			2.6				5.6				-				3
	Counterparties without offsetting position - assets			2.5				-				2.5				-
	Counterparties without offsetting position - liabilities			-				3.8				-				3.8
			$	5.1			$	9.4			$	2.5			$	6.8
	Our payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders.
	The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $55.0 million as of December 31, 2014. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented.
	The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense for the periods indicated:
			Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow Hedging Relationships		2014				2013				2012
Commodity contracts		$	59.8			$	(5.8	)		$	76.4
		Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)		2014				2013				2012
Interest expense, net		$	(2.4	)		$	(6.1	)		$	(7.9	)
Revenues			(4.2	)			21.2				43.9
		$	(6.6	)		$	15.1			$	36
Our consolidated earnings are also affected by our use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.
				Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated		Location of Gain Recognized		2014				2013				2012
as Hedging Instruments		in Income on Derivatives
Commodity contracts		Revenue		$	(5.5	)		$	(0.1	)		$	0.7
The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2017 based on year-end valuations.
		31-Dec-14				31-Dec-13
Commodity hedges (1)		$	60.3			$	(3.7	)
Interest rate hedges			-				(2.4	)
-1	Includes deferred net gains of $44.3 million related to contracts that will be settled and reclassified to revenue over the next 12 months.
See Note 14 for additional disclosures related to derivative instruments and hedging activities.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Fair Value Measurements	Note 14 — Fair Value Measurements
	Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
	Fair Value of Derivative Financial Instruments
	Our derivative instruments consist of financially settled commodity swaps and option contracts and fixed-price commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using a discounted cash flow model for swaps and a standard option-pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold.
	The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This financial position of these derivatives at December 31, 2014, a net asset position of $55.0 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net asset of $38.3 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $71.9 million, ignoring an adjustment for counterparty credit risk.
	Fair Value of Other Financial Instruments
	Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
		·	The TRP Revolver and Securitization Facility are based on carrying value, which approximates fair value as the interest rates is based on prevailing market rates; and
		·	Senior unsecured notes are based on quoted market prices derived from trades of the debt.
	Fair Value Hierarchy
	We categorize the inputs to the fair value measurements of financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
		·	Level 1 – observable inputs such as quoted prices in active markets;
		·	Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
		·	Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
	The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
			31-Dec-14
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
	Assets from commodity derivative contracts (1)		$	60.2		$	60.2		$	-	$	58.4	$	1.8
	Liabilities from commodity derivative contracts (1)			5.2			5.2			-		5.1		0.1
	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
	Cash and cash equivalents			72.3			72.3			-		-		-
	Senior secured revolving credit facility			-			-			-		-		-
	Senior unsecured notes			2,783.40			2,731.50			-		2,731.50		-
	Accounts receivable securitization facility			182.8			182.8			182.8		-		-
			31-Dec-13
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts		$	5.1		$	5.1		$	-	$	3.4	$	1.7
	Liabilities from commodity derivative contracts			9.4			9.4			-		8.4		1
	Badlands contingent consideration liability			-			-			-		-		-
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			57.5			57.5			-		-		-
	Senior secured revolving credit facility			395			395			-		395		-
	Senior unsecured notes			2,230.60			2,253.50			-		2,253.50		-
	Accounts receivable securitization facility			279.7			279.7			-		279.7		-
	-1	The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
	Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets
	We reported certain of our natural gas swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
	The fair value of these natural gas swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
	As of December 31, 2014, we had five natural gas swaps categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.
	The Badlands acquisition agreement also provided for a contingent payment of $50 million conditioned on achieving stipulated crude gathering volumes by mid-2014. In 2012, we recorded a contingent consideration liability of $15.3 million as part of the purchase consideration for the Badlands acquisition (see Note 4). The fair value of this contingent liability was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA. These probability-based inputs are not observable; the entire valuation of the contingent consideration is categorized in Level 3. The contingent period expired June 2014, with no payment required.
	The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
			Commodity Derivative Contracts (Asset)/Liability			Contingent Liability
	Balance, December 31, 2011		$	-		$	-
	Valuation of contingent liability			-			15.3
	Settlements included in Revenue			(0.1	)		-
	Unrealized losses included in OCI			0.7			-
	Balance, December 31, 2012			0.6			15.3
	Settlements included in Revenue			(1.3	)		-
	Change in valuation of contingent liability included in Other Income			-			(15.3	)
	Balance, December 31, 2013			(0.7	)		-
	Settlements included in Revenue			(0.2	)		-
	Unrealized gains included in OCI			(1.1	)
	Transfers out of Level 3			0.3			-
	Balance, December 31, 2014		$	(1.7	)	$	-
	During 2014, we transferred $0.3 million in derivative assets out of Level 3 and into Level 2. This transfer related to long-term OTC swaps for natural gas and NGL products with deliveries for which observable market prices were available.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Note 15 — Related Party Transactions
	We do not have any employees. Targa provides operational, general and administrative and other services to us, associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
	The Partnership Agreement between Targa and us, with Targa as the general partner of the Partnership, governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.
	The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
		2014		2013		2012
	Targa billings of payroll and related costs included in operating expense	$	124.9	$	109.7	$	97.2
	Targa allocation of general & administrative expense		129.4		134.3		124
	Cash distributions to Targa based on unit ownership		180.7		138.2		92.7
	Cash contributions from Targa to maintain its
	2% general partner ownership		7.7		10.8		11.5
	Purchase of common units by Targa		-		-		49.8
	Transactions with Unconsolidated Affiliate
	For the years 2014, 2013 and 2012, transactions with GCF included in revenues were $0.8 million, $0.4 million and $0.1 million. For the same periods, transactions with GCF included in costs and expenses were $7.6 million, $6.3 million and $1.9 million. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities. We are subject to paying a deficiency fee in instances where we do not deliver our minimum volume requirements as outlined in the fractionation agreements with GCF.

Commitments_Leases

Commitments (Leases)	12 Months Ended
	Dec. 31, 2014
Commitments (Leases) [Abstract]
Commitments (Leases)	Note 16 — Commitments (Leases)
	Future lease obligations are presented below in aggregate and for each of the next five fiscal years.
			In Aggregate		2015		2016		2017		2018		2019
	Operating leases (1)		$	28.9	$	7.7	$	7.4	$	5.9	$	4.6	$	3.3
	Land site lease and right-of-way (2)			9.5		2		2		2		1.8		1.7
			$	38.4	$	9.7	$	9.4	$	7.9	$	6.4	$	5
	-1	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-2	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.
	Total expenses incurred under the above lease obligations were:
			2014		2013		2012
	Operating leases (1)		$	24.4	$	23.3	$	16.1
	Land site lease and right-of-way			4.1		3.6		3.3
	-1	Includes short-term leases for items such as compressors and equipment.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2014
Contingencies [Abstract]
Contingencies	Note 17 - Contingencies
	Environmental
	Environmental liabilities were not significant as of December 31, 2014.
	Legal Proceedings
	Litigation Related to the Atlas Mergers
	Targa Shareholder Litigation
	On January 28, 2015, a public shareholder of TRC (the “TRC Plaintiff”) filed a putative class action and derivative lawsuit against TRC (as a nominal defendant), its directors at the time of the ATLS Merger (the “TRC Director Defendants”), and ATLS (together with TRC and the TRC Director Defendants, the “TRC Lawsuit Defendants”).  This lawsuit is styled Inspired Investors v. Joe Bob Perkins, et al., in the District Court of Harris County, Texas (the “TRC Lawsuit”).
	The TRC Plaintiff alleges a variety of causes of action challenging the disclosures related to the ATLS Merger. Generally, the TRC Plaintiff alleges that the TRC Director Defendants breached their fiduciary duties.  The TRC Plaintiff further alleges that the registration statement filed on January 22, 2015 fails to disclose allegedly material details concerning (i) Wells Fargo Securities, LLC’s and the TRC Director Defendants’ supposed conflicts of interest with respect to the ATLS Merger, (ii) TRC’s financial projections, (iii) the background of the ATLS Merger, and (iv) Wells Fargo Securities, LLC’s analysis of the ATLS Merger.
	Based on these allegations, the TRC Plaintiff seeks to enjoin the TRC Lawsuit Defendants from proceeding with or consummating the ATLS Merger unless and until TRC discloses the allegedly material omitted details. To the extent that the ATLS Merger is consummated before injunctive relief is granted, the TRC Plaintiff seeks to have the ATLS Merger rescinded. The TRC Plaintiff also seeks recissory damages and attorneys’ fees.
	Only two of the TRC Lawsuit Defendants have been served at this time, these defendants’ date to answer, move to dismiss, or otherwise respond to the TRC Lawsuit is March 2, 2015. The remaining TRC Lawsuit Defendants’ date to answer, move to dismiss or otherwise respond to the TRC Lawsuit has not yet been set. Targa cannot predict the outcome of this or any other lawsuit that might be filed subsequent to the date of the filing of this Annual Report, nor can Targa or Atlas predict the amount of time and expense that will be required to resolve the TRC Lawsuit. To resolve this matter, Targa published supplemental disclosures on February 11, 2015 and the parties are currently working on settlement documentation.
	Atlas Unitholder Litigation
	Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, Atlas Pipeline Partners GP, LLC, the general partner of APL (“APL GP”), its managers, TRC, the Partnership, the general partner and Trident MLP Merger Sub LLC (the “APL Lawsuit Defendants”). These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma (the “Tulsa Lawsuit”); (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania though the Tulsa Lawsuit has since been voluntarily dismissed. The Evnin, Greenthal, Welborn and Feldbaum lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). In October and November 2014, two public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, the “Atlas Lawsuit Plaintiffs”) filed putative class action lawsuits against ATLS, ATLS Energy GP, LLC, the general partner of ATLS (“ATLS GP”), its managers, TRC and Trident GP Merger Sub LLC (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, the “Atlas Lawsuit Defendants”). These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania (the “ATLS Lawsuits”). The ATLS Lawsuits have been consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit” and, together with the Consolidated APL Lawsuit, the “Consolidated Atlas Lawsuits”), though the Kane lawsuit has since been voluntarily dismissed.
	The Atlas Lawsuit Plaintiffs allege a variety of causes of action challenging the Atlas Mergers. Generally, the APL Plaintiffs allege that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) TRC, the Partnership, the general partner, Trident MLP Merger Sub LLC, APL, ATLS and APL GP have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The APL Plaintiffs further allege that (a) the premium offered to APL’s unitholders is inadequate, (b) APL agreed to contractual terms that will allegedly dissuade other potential acquirers from seeking to acquire APL, and (c) APL GP’s managers favored their self-interests over the interests of APL’s unitholders. The APL Plaintiffs in the Consolidated APL Lawsuit also allege that the registration statement filed on November 19, 2014 fails, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the Transactions; (ii) Targa and Atlas’ financial projections; and (iii) the background of the Transactions. Generally, the ATLS Plaintiffs allege that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, Trident GP Merger Sub LLC, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further allege that (a) the premium offered to the ATLS unitholders is inadequate, (b) ATLS agreed to contractual terms that will allegedly dissuade other potential acquirers from seeking to acquire ATLS, (c) ATLS GP’s directors favored their self-interests over the interests of the ATLS unitholders and (d) the registration statement fails to disclose allegedly material details concerning, among other things, (i) Wells Fargo Securities, LLC, Stifel, Nicolaus & Company, Incorporated, and Deutsche Bank Securities Inc.’s analyses of the Transactions; (ii) Targa and Atlas’ financial projections; and (iii) the background of the Transactions.
	Based on these allegations, the Atlas Lawsuit Plaintiffs sought to enjoin the Atlas Lawsuit Defendants from proceeding with or consummating the Atlas Mergers unless and until APL and ATLS adopted and implemented processes to obtain the best possible terms for their respective unitholders. To the extent that the Atlas Mergers were consummated before injunctive relief was granted, the Atlas Lawsuit Plaintiffs sought to have the Atlas Mergers rescinded. The Atlas Lawsuit Plaintiffs also sought damages and seek attorneys’ fees.
	The parties to the Consolidated Atlas Lawsuits agreed to settle the Consolidated Atlas Lawsuits on February 9, 2015.  In general, the settlements provide that in consideration for the dismissal of the Consolidated Atlas Lawsuits, ATLS and APL will provide supplemental disclosures regarding the Atlas Mergers in a filing with the SEC on Form 8-K, which ATLS and APL did on February 11, 2015. The Atlas Lawsuit Defendants agreed to make such supplemental disclosures solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and deny that any supplemental disclosure was or is required under any applicable rule, statute, regulation or law. The parties to the Consolidated Atlas Lawsuits are drafting settlement agreements and expect to seek court approval of the settlements.
	We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. See “Item 1. Business—Regulation of Operations” and “Item 1. Business—Environmental, Health and Safety Matters.”

Significant_Risks_and_Uncertai

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2014
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Note 18 — Significant Risks and Uncertainties
	Nature of Operations in Midstream Energy Industry
	We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
	Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.
	A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
	The principal market risks are exposure to changes in commodity prices, as well as changes in interest rates.
	Commodity Price Risk
	A majority of the revenues from the gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control.
	In an effort to reduce the variability of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expected natural gas equity volumes through 2017, NGL equity volumes through 2015 and condensate equity volumes through 2017. These derivative financial instruments include swaps and purchased puts (or floors). We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGLs and pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances.
	Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure.
	Interest Rate Risk
	We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our TRP Revolver and Securitization Facility.
	Counterparty Risk – Credit and Concentration
	Derivative Counterparty Risk
	Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
	We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties, and would reduce our maximum loss due to counterparty credit risk by $4.4 million as of December 31, 2014. The range of losses attributable to our individual counterparties would be between $3.3 million and $27.5 million, depending on the counterparty in default.
	Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
	Customer Credit Risk
	We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.
	The following table summarizes the activity affecting our allowance for bad debts:
		2014			2013			2012
	Balance at beginning of year	$	0.9		$	0.7		$	2.2
	Additions		-			0.2			-
	Deductions		(0.9	)		-			(1.5	)
	Balance at end of year	$	-		$	0.9		$	0.7
	Significant Commercial Relationship
		2014			2013			2012
	% of consolidated revenues
	Chevron Phillips Chemical Company LLC		4	%		8	%		10	%
	All transactions in the above table were associated with the Marketing and Distribution segment.
	Casualty or Other Risks
	Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15.
	Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
	If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident.

Other_Operating_Income_Expense

Other Operating (Income) Expense	12 Months Ended
	Dec. 31, 2014
Other Operating (Income) Expense [Abstract]
Other Operating (Income) Expense	Note 19 — Other Operating (Income) Expense
			2014			2013		2012
	Loss (gain) on sale or disposal of assets (1)		$	(4.8	)	$	3.9	$	15.6
	Casualty loss			0.1			4.3		3.6
	Miscellaneous business tax			0.4			0.7		0.7
	Other			1.3			0.7		-
			$	(3.0	)	$	9.6	$	19.9
	-1	Includes a $15.4 million loss in 2012 due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 20 — Supplemental Cash Flow Information
			2014		2013			2012
	Cash:
	Interest paid, net of capitalized interest (1)		$	131	$	119.1		$	92.5
	Income taxes paid, net of refunds			2.7		2.3			2.3
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			14.8		30.4			3
	Badlands contingent consideration recorded at acquisition date			-		-			15.3
	Accrued distribution equivalent rights			1.4		1.7			0.5
	Change in receivables from unit offerings			1		-			-
	Change in capital accruals			19		(0.4	)		(34.4	)
	Transfers from materials and supplies inventory to property, plant and equipment			4.6		20.5			-
	Change in ARO cash flow estimate			2.1		1.4			(1.0	)
	-1	Interest capitalized on major projects was $16.1 million, $28.0 million and $13.6 million for 2014, 2013 and 2012.

Compensation_Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2014
Compensation Plans [Abstract]
Compensation Plans	Note 21 — Compensation Plans
	For the years ended December 31, 2014, 2013 and 2012 our results include compensation expenses from the following sources:
	Partnership Long-Term Incentive Plan
		Performance Units - Equity-settled
		Director Grants
	Allocated compensation cost related to:
		TRC Long-Term Incentive Plan — Cash-settled Performance Units
		2010 TRC Stock Incentive Plan — Restricted Stock Awards
		2010 TRC Stock Incentive Plan — Restricted Stock Units Awards
		Targa 401(k) Plan
	Long-Term Incentive Plans
	Performance Units
	In 2007, both Targa and we adopted Long-Term Incentive Plans (“LTIP”) for employees, consultants, directors and non-employee directors of Targa and its affiliates who perform services for Targa or its affiliates. The performance units granted under these plans are linked to the performance of our common units. These plans provide for, among other things, the grant of both cash-settled and equity-settled performance units. Performance unit awards may also include distribution equivalent rights (“DERs”). The LTIPs are administered by the compensation committee (the “Committee”) of the Targa Board of Directors. Total units authorized under the LTIP are 1,680,000.
	Each performance unit will entitle the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determined from our ranking in a defined peer group. Currently, the performance period for most awards is three years, except for certain awards granted in December 2013, which provide for two, three or four-year vesting periods. The grantee will receive the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vesting percentage. DERs are cash settled for both paid in cash and equity-settled performance units.
	Compensation cost for equity-settled performance units is recognized as an expense over the performance period based on fair value at the grant date. Fair value is calculated using a simulated unit price that incorporates peer ranking. DERs associated with equity-settled performance units are accrued over the performance period as a reduction of owners’ equity.
	Compensation expense for cash-settled performance units and any related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the performance period we must record an accrued expense based on an estimate of that future pay-out. Targa used a Monte Carlo simulation model to estimate accruals throughout the vesting period. In 2012, Targa changed the volatility assumption in the Monte Carlo simulation model from implied volatility to historical volatility. We consider historical volatility to be more appropriate than implied volatility because it provides a more reliable indication of future volatility.
	Subsequent Event. On January 21, 2015, the Committee made awards to the executive management of the general partner for the 2015 compensation cycle of 103,760 equity-settled performance units under our LTIP that will vest in June 2018.
	Director Grants
	Starting in 2011, the common units granted to our non-management directors vested immediately at the grant date.
	The following table summarizes activity of the common unit-based awards granted to our Directors for the years ended December 31, 2014, 2013 and 2012 (in units and dollars):
			Number of				Weighted Average
			units				Grant-Date Fair
							Value
	Outstanding at December 31,  2011			19,831			$	16.31
	Granted			9,980				38.72
	Vested			(25,311	)			23.86
	Outstanding at December 31,  2012			4,500				23.51
	Granted			12,780				39.33
	Vested			(17,280	)			35.21
	Outstanding at December 31,  2013			-				-
	Granted			8,740				50.29
	Vested			(8,740	)			50.29
	Outstanding at December 31,  2014			-				-
	Subsequent Event. On January 21, 2015, the Committee made awards of 10,565 of our common units (2,113 units to each of our non-management directors). The awards vested immediately at the grant date.
	TRC Cash-settled Performance Units
	The following table summarizes the cash-settled performance units for the year ended 2014 awarded under the Targa LTIP (in units and millions of dollars):
			Program Year
			2011 Plan				2012 Plan			2013 Plan			2014 Plan			Total
	Units outstanding January 1, 2014			124,870				142,460			144,960			-			412,290
	Granted			-				-			-			122,950			122,950
	Vested and paid			(123,570	)			-			-			-			(123,570	)
	Forfeited			(1,300	)			(4,000	)		(2,850	)		(590	)		(8,740	)
	Units outstanding December 31, 2014			-				138,460			142,110			122,360			402,930
	Calculated fair market value as of December 31, 2014						$	8.8		$	6.5		$	3.7		$	19
	Current liability						$	7.3		$	-		$	-		$	7.3
	Long-term liability							-			3.1			0.5			3.6
	Liability as of December 31, 2014						$	7.3		$	3.1		$	0.5		$	10.9
	To be recognized in future periods						$	1.5		$	3.4		$	3.2		$	8.1
	Vesting date						Jun-15			Jun-16			Jun-17
	The remaining weighted average recognition period for the unrecognized compensation cost is approximately 1.7 years.
	2010 TRC Stock Incentive Plan
	The Targa Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”).
	Restricted Stock Awards – Total shares authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends.
	The following table summarizes the restricted stock awards in shares and in dollars for the years indicated:
			Number of shares				Weighted-average
							Grant-Date Fair Value
	Outstanding at December 31, 2011			1,434,220			$	22.67
	Granted (1)			91,090				42.5
	Forfeited			(8,930	)			23.99
	Vested (2)			(805,350	)			22
	Outstanding at December 31, 2012			711,030				25.95
	Granted (1)			30,623				57.59
	Forfeited			(2,740	)			27.28
	Vested (2)			(534,940	)			22
Outstanding at December 31, 2013			203,973				41.05
Granted			-				-
Forfeited			(1,980	)			42.82
Vested (3)			(82,800	)			33.37
Outstanding at December 31, 2014			119,193				46.35
-1	These awards will cliff vest at the end of three years.
-2	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures.  Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
-3	Targa repurchased 8,113, 12,849 and 1,006 shares from employees at $96.52, $129.46 and $137.64 per share on February 14th, August 1st , and August 22nd  of 2014 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
Restricted Stock Units (“RSUs”) Awards – RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated.
						Weighted-average
		Number of shares				Grant-Date Fair Value
Outstanding at December 31, 2012			-			$	-
Granted			55,790				69.9
Forfeited			(240	)			67.07
Outstanding at December 31, 2013			55,550				69.92
Granted			54,357				112.89
Forfeited			(1,440	)			75.81
Vested			(100	)			67.07
Outstanding at December 31, 2014			108,367				91.41
Subsequent Event
In January 2015, the committee made restricted stock units awards of 32,372 shares to executive management under the TRC Plan for the 2015 compensation cycle that will cliff vest in three years from the grant date.
On January 12, 2015, Targa repurchased 5,930 shares of grants issued in January 2012 and vested in 2015 at $89.27 per share to satisfy the employee’s minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded in treasury stock at cost.
The following table summarizes the compensation expenses under the various share-based compensation plans recognized for the years indicate:
		2014				2013			2012
Equity-Settled Performance Units		$	8.8			$	5.5		$	3.1
Director Grants			0.4				0.5			0.5
Allocated from Targa
TRC LTIP - Cash-Settled Performance Units			11				21.9			14.2
2010 TRC Stock Incentive Plan - Restricted Stock			2.2				6.3			13.7
2010 TRC Stock Incentive Plan - Restricted Stock Units			2.5				0.4			-
The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various share-based compensation plans as of December 31, 2014:
	Unrecognized Compensation Expense				Weighted Average Remaining Vesting Period
	(In millions)				(In years)
Equity-Settled Performance Units		$	14.1				2
2010 TRC Stock Incentive Plan - Restricted Stock			1.1				0.9
2010 TRC Stock Incentive Plan - Restricted Stock Units			7				2.3
The total fair value of share-based awards on the dates they vested are as follows:
		2014				2013			2012
Equity-Settled Performance units		$	10			$	-		$	-
Accrued DERs settled for Equity - Settled Performance units			1.6				-			-
Director Grants			0.4				0.7			1
TRC Cash-Settled performance units			14.7				25.2			22.2
2010 TRC Stock Incentive Plan - Restricted Stock (1)			7.1				42.2			40.3
Accrued dividends settled			0.5				2.4			2
-1	Targa recognized $1.0 million, $1.6 million and $1.3 million in tax benefits for 2014, 2013 and 2012 that were associated with the vesting of the restricted stock.
Targa 401(k) Plan
Targa has a 401(k) plan whereby it matches 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan).  Targa also contributes an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $10.5 million, $9.6 million and $8.7 million during 2014, 2013 and 2012.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	Note 22 — Segment Information
	We report our operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities on reported profits are reported in Other.
	Our Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Field Gathering and Processing segment's assets are located in North Texas, the Permian Basin of West Texas and Southeast New Mexico and in North Dakota. The Coastal Gathering and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
	Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations, including services to LPG exporters, as well as transporting natural gas and NGLs.
	Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for the LPG export market; and storing and terminaling refined petroleum products. These assets are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and Lake Charles, Louisiana.
	Our Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products for resale in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to us from our Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.
	Other contains the results of our commodity hedging activities included in operating margin. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.
	Our reportable segment information is shown in the following tables:
		Year Ended December 31, 2014
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	197.4		$	355		$	99.1		$	6,951.70	$	(8.0	)	$	-		$	7,595.20
	Fees from midstream services		190.3			34.4			293.6			503		-			-			1,021.30
			387.7			389.4			392.7			7,454.70		(8.0	)		-			8,616.50
	Intersegment revenues
	Sales of commodities		1,491.20			577.6			4.4			486.7		-			(2,559.9	)		-
	Fees from midstream services		5.2			-			308.3			30.1		-			(343.6	)		-
			1,496.40			577.6			312.7			516.8		-			(2,903.5	)		-
	Revenues	$	1,884.10		$	967		$	705.4		$	7,971.50	$	(8.0	)	$	(2,903.5	)	$	8,616.50
	Operating margin	$	372.3		$	77.6		$	445.1		$	249.6	$	(8.0	)	$	-		$	1,136.60
	Other financial information:
	Total assets (1)	$	3,409.00		$	367.2		$	1,717.30		$	708.5	$	60.2		$	115		$	6,377.20
	Capital expenditures	$	423.1		$	14		$	274.4		$	30.2	$	-		$	6.1		$	747.8
	(1) Corporate assets primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our long-term debt
		Year Ended December 31, 2013
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	188.8		$	305		$	140.5		$	5,072.40	$	21.4		$	0.1		$	5,728.20
	Fees from midstream services		113.9			33.6			216			223.3		-			(0.1	)		586.7
			302.7			338.6			356.5			5,295.70		21.4			-			6,314.90
	Intersegment revenues
	Sales of commodities		1,218.90			642.2			3.9			478.6		-			(2,343.6	)		-
	Fees from midstream services		3.4			1			176.5			29.8		-			(210.7	)		-
			1,222.30			643.2			180.4			508.4		-			(2,554.3	)		-
	Revenues	$	1,525.00		$	981.8		$	536.9		$	5,804.10	$	21.4		$	(2,554.3	)	$	6,314.90
	Operating margin	$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	801.5
	Other financial information:
	Total assets	$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	5,971.40
	Capital expenditures	$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	1,034.50
		Year Ended December 31, 2012
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	172.7		$	240.6		$	184.4		$	4,680.20	$	41.1		$	-		$	5,319.00
	Fees from midstream services		39.5			23.6			170.7			124.2		-			(0.1	)		357.9
			212.2			264.2			355.1			4,804.40		41.1			(0.1	)		5,676.90
	Intersegment revenues
	Sales of commodities		1,150.70			701.1			1.8			565		-			(2,418.6	)		-
	Fees from midstream services		1.3			0.1			106.5			32		-			(139.9	)		-
			1,152.00			701.2			108.3			597		-			(2,558.5	)		-
	Revenues	$	1,364.20		$	965.4		$	463.4		$	5,401.40	$	41.1		$	(2,558.6	)	$	5,676.90
	Operating margin	$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	691.7
	Other financial information:
	Total assets	$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	5,025.70
	Capital expenditures	$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	616.7
	Business acquisitions	$	970.4		$	25.8		$	-		$	-	$	-		$	-		$	996.2
The following table shows our consolidated revenues by product and service for the periods presented:
	2014			2013			2012
Sales of commodities
Natural gas	$	1,409.30		$	1,224.70		$	926.9
NGL		5,960.10			4,224.00			4,055.70
Condensate		134.3			121.8			114.1
Petroleum products		96.3			136			180.1
Derivative settlements		(4.8	)		21.7			42.2
		7,595.20			5,728.20			5,319.00
Fees from midstream services
Fractionating and treating		208.9			133.9			110.1
Storage, terminaling, transportation and export		548.1			280.3			162.5
Gathering and processing		196.9			114.1			45
Other		67.4			58.4			40.3
		1,021.30			586.7			357.9
Total revenues	$	8,616.50		$	6,314.90			5,676.90
The following table shows a reconciliation of operating margin to net income for the periods presented:
	2014			2013			2012
Reconciliation of operating margin to net income:
Operating margin	$	1,136.60		$	801.5		$	691.7
Depreciation and amortization expense		(346.5	)		(271.6	)		(197.3	)
General and administrative expense		(139.8	)		(143.1	)		(131.6	)
Interest expense, net		(143.8	)		(131.0	)		(116.8	)
Other, net		3.4			5.7			(38.6	)
Income tax expense		(4.8	)		(2.9	)		(4.2	)
Net income	$	505.1		$	258.6		$	203.2

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Data (Unaudited) [Abstract]
Selected Quarterly Financial Data (Unaudited)	Note 23 — Selected Quarterly Financial Data (Unaudited)
	Our results of operations by quarter for the years ended December 31, 2014 and 2013 were as follows:
		First		Second		Third		Fourth		Total
		Quarter		Quarter		Quarter		Quarter
		(In millions, except per unit amounts)
	2014
	Revenues	$	2,294.70	$	2,000.60	$	2,288.30	$	2,032.90	$	8,616.50
	Gross margin		379.6		384		407.8		398.2		1,569.60
	Operating income		160.6		152.9		171.4		168.4		653.3
	Net income		131.3		120.9		138.2		114.7		505.1
	Net income allocable to limited partners		88.6		73		89.7		67.7		319
	Net income per limited partner unit
	- basic	$	0.79	$	0.64	$	0.78	$	0.58	$	2.78
	- diluted	$	0.78	$	0.64	$	0.78	$	0.58	$	2.77
	2013
	Revenues	$	1,373.80	$	1,370.50	$	1,466.10	$	2,104.50	$	6,314.90
	Gross margin		260.3		265.2		297.1		355.1		1,177.70
	Operating income		76.2		63.2		91		146.8		377.2
	Net income		45.3		32.7		65		115.6		258.6
	Net income allocable to limited partners		16.1		1.2		31.6		77.1		126
	Net income per limited partner unit
	- basic	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	- diluted	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Significant Accounting Policies [Abstract]
Consolidation Policy	Consolidation Policy
	Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
	We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.
Cash and Cash Equivalents	Cash and Cash Equivalents
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Comprehensive Income	Comprehensive Income
	Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as hedges.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts
	Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
Inventories	Inventories
	Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment.  Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method.
Product Exchanges	Product Exchanges
	Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances	Gas Processing Imbalances
	Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments	Derivative Instruments
	We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives.
	If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
	If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues.
	We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
	The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period.
	We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
	For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis and report the related fair value on a gross basis.
Property, Plant and Equipment	Property, Plant and Equipment
	Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
	Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
	Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
	We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
Intangible Assets	Intangible Assets
	Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers.
Asset Retirement Obligations ("AROs")	Asset Retirement Obligations (“AROs”)
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing.
	Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.
Debt Issue Costs	Debt Issue Costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
Accounts Receivable Securitization Facility	Accounts Receivable Securitization Facility
	Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows.
Environmental Liabilities and Other Loss Contingencies	Environmental Liabilities and Other Loss Contingencies
	Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.
Income Taxes	Income Taxes
	We generally are not subject to federal income taxes.   For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners.  The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the consolidated statement of income.  We are also subject to the Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.
Noncontrolling Interests	Noncontrolling Interests
	Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of the balance sheet. In the statements of operations and statements of comprehensive income, noncontrolling interests reflects the attribution of results to third-party investors.
Revenue Recognition	Revenue Recognition
	Our operating revenues are primarily derived from the following activities:
		•	sales of natural gas, NGLs, condensate, crude oil and petroleum products;
		•	services related to compressing, gathering, treating, and processing of natural gas; and
		•	services related to NGL fractionation, terminaling and storage, transportation and treating.
	We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
	For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above.
	We generally report sales revenues gross in our consolidated statements of operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis.
Unit-Based Compensation	Unit-Based Compensation
	We award unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award.
Earnings per Unit	Earnings per Unit
	We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU.
	The limited partners’ net income per unit is based on net income after allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period.
Use of Estimates	Use of Estimates
	When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Recent Accounting Pronouncements	Recent Accounting Pronouncements
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2014, limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have, or will have, a major effect on operations and financial results.  The amendment requires expanded disclosures for discontinued operations and also requires additional disclosures regarding disposals of individually significant components that do not qualify as discontinued operations. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five-step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
	The revenue recognition standard will be effective for us starting in the first quarter of 2017. Early adoption is not permitted. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in our first quarter report in 2017. We have commenced our analysis of the new standard and its impact on our revenue recognition practices.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendment is effective for the annual period beginning after December 15, 2016, and for annual and interim periods thereafter, with early adoption permitted. The amendment requires an entity’s management to evaluate for each annual and interim reporting period whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued.  If substantial doubt is raised, further analysis and disclosures are required, including management’s plans to mitigate the adverse conditions or events.
	In November 2014, FASB issued ASU No. 2014-17, Business Combinations (Topic 805): Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force), with an effective date of November 18, 2014. The amendment provides an acquired entity the option to apply push-down accounting in its separate financial statements when a change-in-control event occurs.

Basis_of_Presentation_Tables

Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2014
Basis of Presentation [Abstract]
Revision of Previously Reported Revenues and Product Purchases	We concluded that these misclassifications were not material to any of the periods affected. However, we have revised previously reported revenues and product purchases to correctly report NGL buy-sell transactions on a net basis. Accordingly, Revenues and Product Purchases reported in our Form 10-K filed on February 14, 2014 have been reduced by equal amounts as presented in the following tables. There is no impact on previously reported net income, cash flows, financial position or other profitability measures.
		Year Ended December 31,
		2013			2012
	As Reported:
	Revenues	$	6,556.20		$	5,883.60
	Product Purchases		5,378.50			4,878.90
	Effect of Revisions:
	Revenues		(241.3	)		(206.7	)
	Product Purchases		(241.3	)		(206.7	)
	As Revised:
	Revenues		6,314.90			5,676.90
	Product Purchases		5,137.20			4,672.20

Business_Acquisitions_Tables

Business Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisitions [Abstract]
Summary of Consideration Paid and Determination of Assets and Liabilities Acquired	The following table summarizes the consideration paid for the Badlands acquisition and the determination of the assets and liabilities acquired at the December 31, 2012 acquisition date.
		31-Dec-12
	Cash	$	975.8
	Contingent consideration		15.3
	Total consideration	$	991.1
	Assets acquired and liabilities assumed
	Financial assets	$	35.4
	Inventory		16.2
	Property, plant and equipment		295.3
	Intangible assets		679.6
	Financial liabilities		(35.4	)
	Total net assets	$	991.1
Pro Forma Consolidated Results of Operations	The following table shows the unaudited pro forma consolidated results of operations for the year ended 2012.
		Year Ended December 31, 2012
		(In millions, except per unit amounts)
	Revenues	$	5,907.80
	Net income		157.4
	Net income attributable to limited partners		63.1
	Net income per limited partner unit - Basic and diluted	$	0.63
Schedule of Outstanding APL Senior Notes	The outstanding APL Senior Notes consist of:
	APL Senior Notes	Amount tendered as of
		6-Feb-15
	$500 million 6⅝ due 2020	Less than majority
	$400 million 4¾ due 2021		98.3	%
	$650 million 5⅞% due 2023		91.6	%

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Components of Inventories		31-Dec-14		31-Dec-13
	Commodities	$	157.4	$	136.4
	Materials and supplies		11.5		14.3
		$	168.9	$	150.7

Property_Plant_and_Equipment_a1

Property, Plant and Equipment and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment and Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets		31-Dec-14			31-Dec-13			Estimated useful life
								(In years)
	Gathering systems	$	2,588.60		$	2,230.10		5 to 20
	Processing and fractionation facilities		1,884.10			1,598.00		5 to 25
	Terminaling and storage facilities		1,038.90			715.2		5 to 25
	Transportation assets		359			294.7		10 to 25
	Other property, plant and equipment		149.1			121.3		3 to 25
	Land		95.6			89.5			-
	Construction in progress		399			702.8			-
	Property, plant and equipment		6,514.30			5,751.60
	Accumulated depreciation		(1,689.7	)		(1,406.2	)
	Property, plant and equipment, net	$	4,824.60		$	4,345.40
	Intangible assets	$	681.8		$	681.8			20
	Accumulated amortization		(89.9	)		(28.4	)
	Intangible assets, net	$	591.9		$	653.4

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Changes in Aggregate Asset Retirement Obligations	The changes in our aggregate asset retirement obligations are as follows:
		2014			2013		2012
	Beginning of period	$	50.5		$	45.2	$	42.3
	Change in cash flow estimate		2.1			1.4		(1.0	)
	Accretion expense		4.4			3.9		3.9
	Retirement of ARO		(0.2	)		-		-
	End of period	$	56.8		$	50.5	$	45.2

Investment_in_Unconsolidated_A1

Investment in Unconsolidated Affiliate (Tables)	12 Months Ended
	Dec. 31, 2014
Investment in Unconsolidated Affiliate [Abstract]
Activity Related to Partnership's Investment in Unconsolidated Affiliate	The following table shows the activity related to our unconsolidated 38.8% interest in Gulf Coast Fractionators LP (“GCF”).
			2014			2013			2012
	Beginning of period		$	55.9		$	53.1		$	36.7
	Equity earnings			18			14.8			1.9
	Cash distributions (1)			(23.7	)		(12.0	)		(2.3	)
	Cash calls for expansion projects			-			-			16.8
	End of period		$	50.2		$	55.9		$	53.1
	-1	Includes $5.7 million and $0.5 million distributions received in excess of our share of cumulative earnings for the years ended December 31, 2014 and 2012. Such excess distributions are considered a return of capital and are disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts_Payable_and_Accrued_L1

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Accounts Payable and Accrued Liabilities [Abstract]
Components of Accounts Payable and Accrued Liabilities		31-Dec-14		31-Dec-13
	Commodities	$	416.7	$	529.7
	Other goods and services		108.9		124.7
	Interest		37.3		35.9
	Compensation and benefits		1.3		1.3
	Income and other taxes		13.6		10.9
	Other		14.9		18.7
		$	592.7	$	721.2

Debt_Obligations_Tables

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Obligations [Abstract]
Schedule of Outstanding Debt			31-Dec-14				31-Dec-13
	Current:
	Accounts receivable securitization facility, due December 2015 (1)		$	182.8			$	-
	Long-term:
	Senior secured revolving credit facility, variable rate, due October 2017 (2)			-				395
	Senior unsecured notes, 7⅞% fixed rate, due October 2018 (3)			-				250
	Senior unsecured notes, 6⅞% fixed rate, due February 2021			483.6				483.6
	Unamortized discount			(25.2	)			(28.0	)
	Senior unsecured notes, 6⅜% fixed rate, due August 2022			300				300
	Senior unsecured notes, 5¼% fixed rate, due May 2023			600				600
	Senior unsecured notes, 4¼% fixed rate, due November 2023			625				625
	Senior unsecured notes, 4⅛% fixed rate, due November 2019			800				-
	Accounts receivable securitization facility, due December 2014 (1)			-				279.7
	Total long-term debt			2,783.40				2,905.30
	Total Debt		$	2,966.20			$	2,905.30
	Letters of credit outstanding (1)		$	44.1			$	86.8
	-1	The classification of the Securitization Facility as of December 31, 2014 has changed. The outstanding amounts under the Securitization Facility as of December 31, 2013 were reflected as long-term debt in our Consolidated Balance Sheets because we had the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. As of December 31, 2013, we intended to fund the Securitization Facility’s borrowings either by further extending the termination date of the Securitization Facility or by utilizing the availability under our Senior Secured Revolving Credit Facility. As of December 31, 2014, we intended to fund the Securitization Facility’s borrowings solely through further extensions of the termination date of the Securitization Facility; based on our history of extending the Securitization Facility, most recently through the Third Amendment to the Securitization Facility entered into in December 2014. As a result, all amounts outstanding under the Securitization Facility as of December 31, 2014 are reflected as a current liability in our Consolidated Balance Sheets.
	-2	As of December 31, 2014, availability under our $1.2 billion senior secured revolving credit facility was $1,155.9 million.
	-3	The outstanding balance of the 7⅞% Notes was redeemed in November 2014. See “Senior Unsecured Notes” below.
Schedule of Contractually Scheduled Maturities of Debt Obligations Outstanding	The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2014 for the next five years, and in total thereafter:
							Scheduled Maturities of Debt
			Total				2015			2016			2017		2018			2019		After 2019
	Senior secured revolving credit facility		$	-			$	-		$	-		$	-	$	-		$	-	$	-
	Senior unsecured notes			2,808.60				-			-			-		-			800		2,008.60
	Account receivable securitization facility			182.8				182.8			-			-		-			-		-
	Total		$	2,991.40			$	182.8		$	-		$	-	$	-		$	800	$	2,008.60
Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2014:
			Range of Interest Rates Incurred				Weighted Average Interest Rate Incurred
	Senior secured revolving credit facility			1.9% - 4.5	%			2	%
	Accounts receivable securitization facility			0.9	%			0.9	%
Schedule of Terms of Senior Unsecured Notes Outstanding	The terms of the senior unsecured notes outstanding as of December 31, 2014 were as follows:
	Note Issue		Issue Date		Per Annum Interest Rate				Due Date	Dates Interest Paid
	"6⅞% Notes"		Feb-11			6⅞	%		1-Feb-21	February & August 1st
	"6⅜% Notes"		Jan-12			6⅜	%		1-Aug-22	February & August 1st
	"5¼% Notes"		Oct / Dec 2012			5¼	%		1-May-23	May & November 1st
	"4¼% Notes"		May-13			4¼	%		15-Nov-23	May & November 15th
	"4⅛% Notes"		Oct-14			4⅛	%		15-Nov-19	May & November 15th
Schedule of Redemption Prices for Issued Debt	We may redeem up to 35% of the aggregate principal amount of Notes at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 90 days (180 days for the 6⅜% Notes, 5¼% Notes, 4¼ % Notes and 4⅛% Notes) of the date of the closing of such equity offering.
	Note Issue		Any Date Prior To		Price
	6⅞% Notes		1-Feb-14			106.875	%
	6⅜% Notes		1-Feb-15			106.375	%
	5¼% Notes		1-Nov-15			105.25	%
	4¼% Notes		15-May-16			104.25	%
	4⅛% Notes		15-Nov-19			104.125	%
	We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
	6⅞% Notes						6⅜% Notes						5¼% Notes					4¼% Notes					4⅛% Notes
	Redemption Date:						Redemption Date:						Redemption Date:					Redemption Date:					Redemption Date:
	1-Feb						1-Feb						1-Nov					15-May					15-Nov
	Year		Price				Year			Price			Year		Price			Year		Price			Year		Price
	2016			103.438	%			2017			103.188	%		2017		102.625	%		2018		102.125	%		2016		102.063	%
	2017			102.292	%			2018			102.125	%		2018		101.75	%		2019		101.417	%		2017		101.031	%
	2018			101.146	%			2019			101.063	%		2019		100.875	%		2020		100.708	%	2018 and thereafter			100	%
	2019 and thereafter			100	%		2020 and thereafter				100	%	2020 and thereafter			100	%	2021 and thereafter			100	%
Schedule of Debt Re-acquisitions	The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations:
			2014				2013			2012
	Premium over face value paid upon redemption:
	6⅜ Notes		$	-			$	6.4		$	-
	7⅞ Notes			9.9				-			-
	8¼ Notes			-				-			8.6
	11¼ Notes			-				4.1			-
	Recognition of unamortized discount:
	11¼ Notes			-				2.2			-
	Write-off of deferred debt issue costs:
	6⅜ Notes			-				1			-
	7⅞ Notes			2.5				-			-
	8¼ Notes			-				-			2.5
	11¼ Notes			-				1			-
	Partial write-off of TRP Revolver deferred debt issue costs related to 2012 amendment			-				-			1.7
	Loss on debt redemptions and amendments		$	12.4			$	14.7		$	12.8

Partnership_Units_and_Related_1

Partnership Units and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Partnership Units and Related Matters [Abstract]
Schedule of Distributions	The following table details the distributions declared and/or paid by us during the periods presented.
			Distributions
			Limited		General Partner						Distributions
			Partners								per Limited
	Three Months Ended	Date Paid or to be Paid	Common		Incentive		2%		Total		Partner Unit
			(In millions, except per unit amounts)
	2014
	31-Dec-14	13-Feb-15	$	96.3	$	38.4	$	2.7	$	137.4	$	0.81
	30-Sep-14	14-Nov-14		92.3		36		2.6		130.9		0.7975
	30-Jun-14	14-Aug-14		89.5		33.7		2.5		125.7		0.78
	31-Mar-14	15-May-14		87.2		31.7		2.4		121.3		0.7625
	2013
	31-Dec-13	14-Feb-14		84		29.5		2.3		115.8		0.7475
	30-Sep-13	14-Nov-13		79.4		26.9		2.2		108.5		0.7325
	30-Jun-13	14-Aug-13		75.8		24.6		2		102.4		0.715
	31-Mar-13	15-May-13		71.7		22.1		1.9		95.7		0.6975
	2012
	31-Dec-12	14-Feb-13		69		20.1		1.8		90.9		0.68
	30-Sep-12	14-Nov-12		59.1		16.1		1.5		76.7		0.6625
	30-Jun-12	14-Aug-12		57.3		14.4		1.5		73.2		0.6425
	31-Mar-12	15-May-12		55.5		12.7		1.4		69.6		0.6225

Earnings_per_Limited_Partner_U1

Earnings per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings per Limited Partner Unit [Abstract]
Computation of Basic and Diluted Net Income Per Limited Partner Unit	The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per limited partner unit:
		2014		2013		2012
	Net income	$	505.1	$	258.6	$	203.2
	Less: Net income attributable to noncontrolling interests		37.4		25.1		28.6
	Net income attributable to Targa Resources Partners LP	$	467.7	$	233.5	$	174.6
	Net income attributable to general partner	$	148.7	$	107.5	$	66.7
	Net income attributable to limited partners		319		126		107.9
	Net income attributable to Targa Resources Partners LP	$	467.7	$	233.5	$	174.6
	Weighted average units outstanding - basic		114.7		105.5		90.1
	Net income available per limited partner unit - basic	$	2.78	$	1.19	$	1.2
	Weighted average units outstanding		114.7		105.5		90.1
	Dilutive effect of unvested stock awards		0.4		0.2		0.1
	Weighted average units outstanding - diluted (1)		115.1		105.7		90.2
	Net income available per limited partner unit - diluted	$	2.77	$	1.19	$	1.2
	(1) For the year ended December 31, 2014, approximately 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities [Abstract]
Notional Volume of Commodity Hedges	At December 31, 2014, the notional volumes of our commodity hedges for equity volumes were:
	Commodity		Instrument		Unit		2015				2016				2017
	Natural Gas		Swaps		MMBtu/d			55,551				30,500				5,000
	NGL		Swaps		Bbl/d			1,210				-				-
	Condensate		Swaps		Bbl/d			1,500				1,000				500
Fair Values of Derivative Instruments	The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
				Fair Value as of December 31, 2014								Fair Value as of December 31, 2013
		Balance Sheet		Derivative				Derivative				Derivative				Derivative
		Location		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as hedging instruments
	Commodity contracts	Current		$	44.4			$	-			$	2			$	7.7
	Long-term				15.8				-				3.1				1.4
	Total derivatives designated as hedging instruments			$	60.2			$	-			$	5.1			$	9.1
	Derivatives not designated as hedging instruments
	Commodity contracts	Current		$	-			$	5.2			$	-			$	0.3
	Total derivatives not designated as hedging instruments			$	-			$	5.2			$	-			$	0.3
	Total current position			$	44.4			$	5.2			$	2			$	8
	Total long-term position				15.8				-				3.1				1.4
	Total derivatives			$	60.2			$	5.2			$	5.1			$	9.4
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet	The pro forma impact of reporting derivatives in the Consolidated Balance Sheets on a net basis is as follows:
			Gross Presentation								Pro forma Net Presentation
			Asset				Liability				Asset				Liability
	31-Dec-14		Position				Position				Position				Position
	Current position
	Counterparties with offsetting position		$	35.5			$	4.4			$	31.1			$	-
	Counterparties without offsetting position - assets			8.9				-				8.9				-
	Counterparties without offsetting position - liabilities			-				0.8				-				0.8
				44.4				5.2				40				0.8
	Long-term position
	Counterparties with offsetting position			-				-				-				-
	Counterparties without offsetting position - assets			15.8				-				15.8				-
	Counterparties without offsetting position - liabilities			-				-				-				-
				15.8				-				15.8				-
	Total derivatives
	Counterparties with offsetting position			35.5				4.4				31.1				-
	Counterparties without offsetting position - assets			24.7				-				24.7				-
	Counterparties without offsetting position - liabilities			-				0.8				-				0.8
			$	60.2			$	5.2			$	55.8			$	0.8
	31-Dec-13
	Current position
	Counterparties with offsetting position		$	1.9			$	4.4			$	-			$	2.5
	Counterparties without offsetting position - assets			0.1				-				0.1				-
	Counterparties without offsetting position - liabilities			-				3.6				-				3.6
				2				8				0.1				6.1
	Long-term position
	Counterparties with offsetting position			0.7				1.2				-				0.5
	Counterparties without offsetting position - assets			2.4				-				2.4				-
	Counterparties without offsetting position - liabilities			-				0.2				-				0.2
				3.1				1.4				2.4				0.7
	Total derivatives
	Counterparties with offsetting position			2.6				5.6				-				3
	Counterparties without offsetting position - assets			2.5				-				2.5				-
	Counterparties without offsetting position - liabilities			-				3.8				-				3.8
			$	5.1			$	9.4			$	2.5			$	6.8
Amounts Recorded in OCI and Amounts Reclassified from OCI to Revenue and Expense	The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense for the periods indicated:
			Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Derivatives in Cash Flow Hedging Relationships		2014				2013				2012
	Commodity contracts		$	59.8			$	(5.8	)		$	76.4
			Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Location of Gain (Loss)		2014				2013				2012
	Interest expense, net		$	(2.4	)		$	(6.1	)		$	(7.9	)
	Revenues			(4.2	)			21.2				43.9
			$	(6.6	)		$	15.1			$	36
Gain (Loss) Recognized in Income on Derivatives	The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.
					Gain (Loss) Recognized in Income on Derivatives
	Derivatives Not Designated		Location of Gain Recognized		2014				2013				2012
	as Hedging Instruments		in Income on Derivatives
	Commodity contracts		Revenue		$	(5.5	)		$	(0.1	)		$	0.7
Deferred Gains (Losses) Included in Accumulated OCI	The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2017 based on year-end valuations.
			31-Dec-14				31-Dec-13
	Commodity hedges (1)		$	60.3			$	(3.7	)
	Interest rate hedges			-				(2.4	)
	-1	Includes deferred net gains of $44.3 million related to contracts that will be settled and reclassified to revenue over the next 12 months.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Breakdown by Fair Value Hierarchy Category for Financial Instruments Included in Consolidated Balance Sheets	The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
			31-Dec-14
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
	Assets from commodity derivative contracts (1)		$	60.2		$	60.2		$	-	$	58.4	$	1.8
	Liabilities from commodity derivative contracts (1)			5.2			5.2			-		5.1		0.1
	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
	Cash and cash equivalents			72.3			72.3			-		-		-
	Senior secured revolving credit facility			-			-			-		-		-
	Senior unsecured notes			2,783.40			2,731.50			-		2,731.50		-
	Accounts receivable securitization facility			182.8			182.8			182.8		-		-
			31-Dec-13
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts		$	5.1		$	5.1		$	-	$	3.4	$	1.7
	Liabilities from commodity derivative contracts			9.4			9.4			-		8.4		1
	Badlands contingent consideration liability			-			-			-		-		-
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			57.5			57.5			-		-		-
	Senior secured revolving credit facility			395			395			-		395		-
	Senior unsecured notes			2,230.60			2,253.50			-		2,253.50		-
	Accounts receivable securitization facility			279.7			279.7			-		279.7		-
	-1	The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3	The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
			Commodity Derivative Contracts (Asset)/Liability			Contingent Liability
	Balance, December 31, 2011		$	-		$	-
	Valuation of contingent liability			-			15.3
	Settlements included in Revenue			(0.1	)		-
	Unrealized losses included in OCI			0.7			-
	Balance, December 31, 2012			0.6			15.3
	Settlements included in Revenue			(1.3	)		-
	Change in valuation of contingent liability included in Other Income			-			(15.3	)
	Balance, December 31, 2013			(0.7	)		-
	Settlements included in Revenue			(0.2	)		-
	Unrealized gains included in OCI			(1.1	)
	Transfers out of Level 3			0.3			-
	Balance, December 31, 2014		$	(1.7	)	$	-

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Summary of Transactions with Affiliates	The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
		2014		2013		2012
	Targa billings of payroll and related costs included in operating expense	$	124.9	$	109.7	$	97.2
	Targa allocation of general & administrative expense		129.4		134.3		124
	Cash distributions to Targa based on unit ownership		180.7		138.2		92.7
	Cash contributions from Targa to maintain its
	2% general partner ownership		7.7		10.8		11.5
	Purchase of common units by Targa		-		-		49.8

Commitments_Leases_Tables

Commitments (Leases) (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments (Leases) [Abstract]
Future Lease Obligations for Next Five Fiscal Years	Future lease obligations are presented below in aggregate and for each of the next five fiscal years.
			In Aggregate		2015		2016		2017		2018		2019
	Operating leases (1)		$	28.9	$	7.7	$	7.4	$	5.9	$	4.6	$	3.3
	Land site lease and right-of-way (2)			9.5		2		2		2		1.8		1.7
			$	38.4	$	9.7	$	9.4	$	7.9	$	6.4	$	5
	-1	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-2	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.
Total Expenses on Lease Obligations	Total expenses incurred under the above lease obligations were:
			2014		2013		2012
	Operating leases (1)		$	24.4	$	23.3	$	16.1
	Land site lease and right-of-way			4.1		3.6		3.3
	-1	Includes short-term leases for items such as compressors and equipment.

Significant_Risks_and_Uncertai1

Significant Risks and Uncertainties (Tables)	12 Months Ended
	Dec. 31, 2014
Significant Risks and Uncertainties [Abstract]
Activity Affecting Allowance for Bad Debts	The following table summarizes the activity affecting our allowance for bad debts:
		2014			2013			2012
	Balance at beginning of year	$	0.9		$	0.7		$	2.2
	Additions		-			0.2			-
	Deductions		(0.9	)		-			(1.5	)
	Balance at end of year	$	-		$	0.9		$	0.7
Customer Concentration	Significant Commercial Relationship
		2014			2013			2012
	% of consolidated revenues
	Chevron Phillips Chemical Company LLC		4	%		8	%		10	%

Other_Operating_Income_Expense1

Other Operating (Income) Expense (Tables)	12 Months Ended
	Dec. 31, 2014
Other Operating (Income) Expense [Abstract]
Other Operating (Income) Expense			2014			2013		2012
	Loss (gain) on sale or disposal of assets (1)		$	(4.8	)	$	3.9	$	15.6
	Casualty loss			0.1			4.3		3.6
	Miscellaneous business tax			0.4			0.7		0.7
	Other			1.3			0.7		-
			$	(3.0	)	$	9.6	$	19.9
	-1	Includes a $15.4 million loss in 2012 due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information			2014		2013			2012
	Cash:
	Interest paid, net of capitalized interest (1)		$	131	$	119.1		$	92.5
	Income taxes paid, net of refunds			2.7		2.3			2.3
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			14.8		30.4			3
	Badlands contingent consideration recorded at acquisition date			-		-			15.3
	Accrued distribution equivalent rights			1.4		1.7			0.5
	Change in receivables from unit offerings			1		-			-
	Change in capital accruals			19		(0.4	)		(34.4	)
	Transfers from materials and supplies inventory to property, plant and equipment			4.6		20.5			-
	Change in ARO cash flow estimate			2.1		1.4			(1.0	)
	-1	Interest capitalized on major projects was $16.1 million, $28.0 million and $13.6 million for 2014, 2013 and 2012.

Compensation_Plans_Tables

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Activity of the Common Unit-Based Awards Granted to the Partnership's Directors	The following table summarizes activity of the common unit-based awards granted to our Directors for the years ended December 31, 2014, 2013 and 2012 (in units and dollars):
			Number of				Weighted Average
			units				Grant-Date Fair
							Value
	Outstanding at December 31,  2011			19,831			$	16.31
	Granted			9,980				38.72
	Vested			(25,311	)			23.86
	Outstanding at December 31,  2012			4,500				23.51
	Granted			12,780				39.33
	Vested			(17,280	)			35.21
	Outstanding at December 31,  2013			-				-
	Granted			8,740				50.29
	Vested			(8,740	)			50.29
	Outstanding at December 31,  2014			-				-
Summary of Compensation Expenses under Various Compensation Plans	The following table summarizes the compensation expenses under the various share-based compensation plans recognized for the years indicate:
			2014				2013			2012
	Equity-Settled Performance Units		$	8.8			$	5.5		$	3.1
	Director Grants			0.4				0.5			0.5
	Allocated from Targa
	TRC LTIP - Cash-Settled Performance Units			11				21.9			14.2
	2010 TRC Stock Incentive Plan - Restricted Stock			2.2				6.3			13.7
	2010 TRC Stock Incentive Plan - Restricted Stock Units			2.5				0.4			-
Summary of Unrecognized Compensation Expenses and Approximate Remaining Weighted Average Vesting Periods	The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various share-based compensation plans as of December 31, 2014:
		Unrecognized Compensation Expense				Weighted Average Remaining Vesting Period
		(In millions)				(In years)
	Equity-Settled Performance Units		$	14.1				2
	2010 TRC Stock Incentive Plan - Restricted Stock			1.1				0.9
	2010 TRC Stock Incentive Plan - Restricted Stock Units			7				2.3
Fair Values of Share-Based Awards on the Dates They Vested	The total fair value of share-based awards on the dates they vested are as follows:
			2014				2013			2012
	Equity-Settled Performance units		$	10			$	-		$	-
	Accrued DERs settled for Equity - Settled Performance units			1.6				-			-
	Director Grants			0.4				0.7			1
	TRC Cash-Settled performance units			14.7				25.2			22.2
	2010 TRC Stock Incentive Plan - Restricted Stock (1)			7.1				42.2			40.3
	Accrued dividends settled			0.5				2.4			2
	-1	Targa recognized $1.0 million, $1.6 million and $1.3 million in tax benefits for 2014, 2013 and 2012 that were associated with the vesting of the restricted stock.
Cash-Settled Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Performance Units	The following table summarizes the cash-settled performance units for the year ended 2014 awarded under the Targa LTIP (in units and millions of dollars):
			Program Year
			2011 Plan				2012 Plan			2013 Plan			2014 Plan			Total
	Units outstanding January 1, 2014			124,870				142,460			144,960			-			412,290
	Granted			-				-			-			122,950			122,950
	Vested and paid			(123,570	)			-			-			-			(123,570	)
	Forfeited			(1,300	)			(4,000	)		(2,850	)		(590	)		(8,740	)
	Units outstanding December 31, 2014			-				138,460			142,110			122,360			402,930
	Calculated fair market value as of December 31, 2014						$	8.8		$	6.5		$	3.7		$	19
	Current liability						$	7.3		$	-		$	-		$	7.3
	Long-term liability							-			3.1			0.5			3.6
	Liability as of December 31, 2014						$	7.3		$	3.1		$	0.5		$	10.9
	To be recognized in future periods						$	1.5		$	3.4		$	3.2		$	8.1
	Vesting date						Jun-15			Jun-16			Jun-17
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Restricted Stock Units Awards	The following table summarizes the restricted stock awards in shares and in dollars for the years indicated:
			Number of shares				Weighted-average
							Grant-Date Fair Value
	Outstanding at December 31, 2011			1,434,220			$	22.67
	Granted (1)			91,090				42.5
	Forfeited			(8,930	)			23.99
	Vested (2)			(805,350	)			22
	Outstanding at December 31, 2012			711,030				25.95
	Granted (1)			30,623				57.59
	Forfeited			(2,740	)			27.28
	Vested (2)			(534,940	)			22
	Outstanding at December 31, 2013			203,973				41.05
	Granted			-				-
	Forfeited			(1,980	)			42.82
	Vested (3)			(82,800	)			33.37
	Outstanding at December 31, 2014			119,193				46.35
	-1	These awards will cliff vest at the end of three years.
	-2	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures.  Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
	-3	Targa repurchased 8,113, 12,849 and 1,006 shares from employees at $96.52, $129.46 and $137.64 per share on February 14th, August 1st , and August 22nd  of 2014 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Restricted Stock Units Awards	The following table summarizes the restricted stock awards in shares and in dollars for the years indicated.
							Weighted-average
			Number of shares				Grant-Date Fair Value
	Outstanding at December 31, 2012			-			$	-
	Granted			55,790				69.9
	Forfeited			(240	)			67.07
	Outstanding at December 31, 2013			55,550				69.92
	Granted			54,357				112.89
	Forfeited			(1,440	)			75.81
	Vested			(100	)			67.07
	Outstanding at December 31, 2014			108,367				91.41

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Information by Segment	Our reportable segment information is shown in the following tables:
		Year Ended December 31, 2014
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	197.4		$	355		$	99.1		$	6,951.70	$	(8.0	)	$	-		$	7,595.20
	Fees from midstream services		190.3			34.4			293.6			503		-			-			1,021.30
			387.7			389.4			392.7			7,454.70		(8.0	)		-			8,616.50
	Intersegment revenues
	Sales of commodities		1,491.20			577.6			4.4			486.7		-			(2,559.9	)		-
	Fees from midstream services		5.2			-			308.3			30.1		-			(343.6	)		-
			1,496.40			577.6			312.7			516.8		-			(2,903.5	)		-
	Revenues	$	1,884.10		$	967		$	705.4		$	7,971.50	$	(8.0	)	$	(2,903.5	)	$	8,616.50
	Operating margin	$	372.3		$	77.6		$	445.1		$	249.6	$	(8.0	)	$	-		$	1,136.60
	Other financial information:
	Total assets (1)	$	3,409.00		$	367.2		$	1,717.30		$	708.5	$	60.2		$	115		$	6,377.20
	Capital expenditures	$	423.1		$	14		$	274.4		$	30.2	$	-		$	6.1		$	747.8
	(1) Corporate assets primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our long-term debt
		Year Ended December 31, 2013
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	188.8		$	305		$	140.5		$	5,072.40	$	21.4		$	0.1		$	5,728.20
	Fees from midstream services		113.9			33.6			216			223.3		-			(0.1	)		586.7
			302.7			338.6			356.5			5,295.70		21.4			-			6,314.90
	Intersegment revenues
	Sales of commodities		1,218.90			642.2			3.9			478.6		-			(2,343.6	)		-
	Fees from midstream services		3.4			1			176.5			29.8		-			(210.7	)		-
			1,222.30			643.2			180.4			508.4		-			(2,554.3	)		-
	Revenues	$	1,525.00		$	981.8		$	536.9		$	5,804.10	$	21.4		$	(2,554.3	)	$	6,314.90
	Operating margin	$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	801.5
	Other financial information:
	Total assets	$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	5,971.40
	Capital expenditures	$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	1,034.50
		Year Ended December 31, 2012
		Field			Coastal			Logistics			Marketing		Other			Corporate			Total
		Gathering			Gathering			Assets			and					and
		and			and						Distribution					Eliminations
		Processing			Processing
	Revenues
	Sales of commodities	$	172.7		$	240.6		$	184.4		$	4,680.20	$	41.1		$	-		$	5,319.00
	Fees from midstream services		39.5			23.6			170.7			124.2		-			(0.1	)		357.9
			212.2			264.2			355.1			4,804.40		41.1			(0.1	)		5,676.90
	Intersegment revenues
	Sales of commodities		1,150.70			701.1			1.8			565		-			(2,418.6	)		-
	Fees from midstream services		1.3			0.1			106.5			32		-			(139.9	)		-
			1,152.00			701.2			108.3			597		-			(2,558.5	)		-
	Revenues	$	1,364.20		$	965.4		$	463.4		$	5,401.40	$	41.1		$	(2,558.6	)	$	5,676.90
	Operating margin	$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	691.7
	Other financial information:
	Total assets	$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	5,025.70
	Capital expenditures	$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	616.7
	Business acquisitions	$	970.4		$	25.8		$	-		$	-	$	-		$	-		$	996.2
Revenues by Product and Service	The following table shows our consolidated revenues by product and service for the periods presented:
		2014			2013			2012
	Sales of commodities
	Natural gas	$	1,409.30		$	1,224.70		$	926.9
	NGL		5,960.10			4,224.00			4,055.70
	Condensate		134.3			121.8			114.1
	Petroleum products		96.3			136			180.1
	Derivative settlements		(4.8	)		21.7			42.2
			7,595.20			5,728.20			5,319.00
	Fees from midstream services
	Fractionating and treating		208.9			133.9			110.1
	Storage, terminaling, transportation and export		548.1			280.3			162.5
	Gathering and processing		196.9			114.1			45
	Other		67.4			58.4			40.3
			1,021.30			586.7			357.9
	Total revenues	$	8,616.50		$	6,314.90			5,676.90
Reconciliation of Operating Margin to Net Income	The following table shows a reconciliation of operating margin to net income for the periods presented:
		2014			2013			2012
	Reconciliation of operating margin to net income:
	Operating margin	$	1,136.60		$	801.5		$	691.7
	Depreciation and amortization expense		(346.5	)		(271.6	)		(197.3	)
	General and administrative expense		(139.8	)		(143.1	)		(131.6	)
	Interest expense, net		(143.8	)		(131.0	)		(116.8	)
	Other, net		3.4			5.7			(38.6	)
	Income tax expense		(4.8	)		(2.9	)		(4.2	)
	Net income	$	505.1		$	258.6		$	203.2

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Data (Unaudited) [Abstract]
Results of Operations by Quarter	Our results of operations by quarter for the years ended December 31, 2014 and 2013 were as follows:
		First		Second		Third		Fourth		Total
		Quarter		Quarter		Quarter		Quarter
		(In millions, except per unit amounts)
	2014
	Revenues	$	2,294.70	$	2,000.60	$	2,288.30	$	2,032.90	$	8,616.50
	Gross margin		379.6		384		407.8		398.2		1,569.60
	Operating income		160.6		152.9		171.4		168.4		653.3
	Net income		131.3		120.9		138.2		114.7		505.1
	Net income allocable to limited partners		88.6		73		89.7		67.7		319
	Net income per limited partner unit
	- basic	$	0.79	$	0.64	$	0.78	$	0.58	$	2.78
	- diluted	$	0.78	$	0.64	$	0.78	$	0.58	$	2.77
	2013
	Revenues	$	1,373.80	$	1,370.50	$	1,466.10	$	2,104.50	$	6,314.90
	Gross margin		260.3		265.2		297.1		355.1		1,177.70
	Operating income		76.2		63.2		91		146.8		377.2
	Net income		45.3		32.7		65		115.6		258.6
	Net income allocable to limited partners		16.1		1.2		31.6		77.1		126
	Net income per limited partner unit
	- basic	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	- diluted	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19

Organization_and_Operations_De

Organization and Operations (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Organization and Operations [Abstract]
General partner interest (in hundredths)	2.00%
Ownership interest by related party and subsidiaries (in hundredths)	12.70%
General partner units outstanding (in units)	2,420,124	2,270,680
Common units held by related party (in units)	12,945,659
Increasing cash distributions as percentage of distributable cash for a quarter (in hundredths)	48.00%

Basis_of_Presentation_Details

Basis of Presentation (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues	$2,032.90	$2,288.30	$2,000.60	$2,294.70	$2,104.50	$1,466.10	$1,370.50	$1,373.80	$8,616.50	$6,314.90	$5,676.90
Product Purchases									7,046.90	5,137.20	4,672.20
As Reported [Member]
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues										6,556.20	5,883.60
Product Purchases										5,378.50	4,878.90
Effect of Revisions [Member]
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues										-241.3	-206.7
Product Purchases										-241.3	-206.7
As Revised [Member]
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues										6,314.90	5,676.90
Product Purchases										$5,137.20	$4,672.20

Significant_Accounting_Policie2

Significant Accounting Policies (Details)	Dec. 31, 2014
Income Taxes [Abstract]
Margin tax rate (in hundredths)	1.00%
Earnings per Limited Partner Unit [Abstract]
General partner's interest and incentive distribution rights (in hundredths)	2.00%

Business_Acquisitions_Details

Business Acquisitions (Details) (USD $)	0 Months Ended	12 Months Ended			1 Months Ended	0 Months Ended
	Oct. 13, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015	Feb. 05, 2015	Feb. 06, 2015
	Transaction
Business Acquisition [Line Items]
Contingent consideration			$50,000,000
Pro forma consolidated results of operations [Abstract]
Useful life of acquired definite-lived intangibles		20 years
Number of proposed merger transactions	2
Net proceeds from issuance of senior notes		800,000,000	625,000,000	1,000,000,000
Minimum [Member]
Pro forma consolidated results of operations [Abstract]
Useful life of acquired property, plant equipment		15 years
Maximum [Member]
Pro forma consolidated results of operations [Abstract]
Useful life of acquired property, plant equipment		20 years
Revolving Credit Facility [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount					670,000,000
Term of loan		5 years
5% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount					1,100,000,000
Interest rate on senior notes (in hundredths)					5.00%
Maturity date					31-Dec-18
Net proceeds from issuance of senior notes					1,090,800,000
Senior Secured Term Loan [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount					430,000,000
Term of loan		7 years
Badlands [Member]
Business Acquisition [Line Items]
Contingent consideration				50,000,000
Other income			15,300,000
Consideration paid [Abstract]
Cash				975,800,000
Contingent consideration			0	15,300,000
Total consideration				991,100,000
Assets acquired and liabilities assumed [Abstract]
Financial assets				35,400,000
Inventory				16,200,000
Property, plant and equipment				295,300,000
Intangible assets				679,600,000
Financial liabilities				-35,400,000
Total net assets				991,100,000
Acquisition-related costs				6,100,000
Pro forma consolidated results of operations [Abstract]
Revenues				5,907,800,000
Net income				157,400,000
Net income attributable to limited partners				63,100,000
Net income per limited partner unit - Basic and diluted (in dollars per share)				$0.63
Total estimated consideration				991,100,000
Atlas Pipeline Partners [Member]
Pro forma consolidated results of operations [Abstract]
Processing capacity (in MMcf/D)		1,439
Length of pipelines (in miles)		10,300
Number of years, incentive distribution rights agreed to reduce		4 years
Number of successive quarters, annual distribution is paid		4
Atlas Pipeline Partners [Member] | Subsequent Event [Member]
Consideration paid [Abstract]
Total consideration						5,000,000,000
Pro forma consolidated results of operations [Abstract]
Total estimated consideration						5,000,000,000
Atlas Pipeline Partners [Member] | APL Senior Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Amount to be received per $1,000 principal by APL noteholders if tendered before January 29, 2015					1,015
Amount to be received per $1,000 principal by APL noteholders if tendered after January 29, 2015					985
Atlas Pipeline Partners [Member] | 6 5/8% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount							500,000,000
Interest rate on senior notes (in hundredths)							6.63%
Maturity date		31-Dec-20
Atlas Pipeline Partners [Member] | 4 3/4% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount							400,000,000
Interest rate on senior notes (in hundredths)							4.75%
Maturity date		31-Dec-21
Percentage of tenders received from noteholders (in hundredths)							98.30%
Atlas Pipeline Partners [Member] | 5 7/8% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount							650,000,000
Interest rate on senior notes (in hundredths)							5.88%
Maturity date		31-Dec-23
Percentage of tenders received from noteholders (in hundredths)							91.00%
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member]
Pro forma consolidated results of operations [Abstract]
Reduction in incentive distribution		-37,500,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member]
Pro forma consolidated results of operations [Abstract]
Reduction in incentive distribution		-25,000,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member]
Pro forma consolidated results of operations [Abstract]
Reduction in incentive distribution		-10,000,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member]
Pro forma consolidated results of operations [Abstract]
Reduction in incentive distribution		-5,000,000
Atlas Pipeline Partners [Member] | Current Atlas Pipeline Partners Unitholders [Member]
Pro forma consolidated results of operations [Abstract]
Distribution of common units/shares for each common unit (in shares)		0.5846
One-time cash payment (in dollars per share)		$1.26
Preferred units, cumulative cash distribution		126,500,000
Atlas Energy [Member]
Pro forma consolidated results of operations [Abstract]
Limited partner interest in APL (in hundredths)		5.50%
Distribution of common units (in shares)		10,350,000
Total one-time cash payment		522,000,000
Cash payment for repayment of ATLS outstanding indebtedness		88,000,000
Cash payment related to change of control payments		190,000,000
Atlas Energy [Member] | Subsequent Event [Member]
Consideration paid [Abstract]
Total consideration						1,600,000,000
Pro forma consolidated results of operations [Abstract]
Total estimated consideration						1,600,000,000
Committed financing value					1,100,000,000
Atlas Energy [Member] | 6 5/8% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Amount to be received per $1,000 principal by APL noteholders pursuant to Change of Control Offer					$1,010
Atlas Energy [Member] | Current Atlas Energy Unitholders [Member]
Pro forma consolidated results of operations [Abstract]
Distribution of common units/shares for each common unit (in shares)		0.1809
One-time cash payment (in dollars per share)		$9.12

InventoriesDetails

Inventories(Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Components of inventories [Abstract]
Commodities	$157.40	$136.40
Materials and supplies	11.5	14.3
Total inventories	$168.90	$150.70

Property_Plant_and_Equipment_a2

Property, Plant and Equipment and Intangible Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$6,514.30	$5,751.60
Accumulated depreciation	-1,689.70	-1,406.20
Property, plant and equipment, net	4,824.60	4,345.40
Intangible assets	681.8	681.8
Accumulated Amortization	-89.9	-28.4
Intangible assets, net	591.9	653.4
Estimated useful life for intangible assets	20 years
Estimated amortization expense for intangible assets [Abstract]
2015	80.1
2016	88.3
2017	81.5
2018	67.8
2019	56.8
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	20 years
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,588.60	2,230.10
Gathering Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Gathering Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	20 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,884.10	1,598
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,038.90	715.2
Terminaling and Storage Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Terminaling and Storage Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Transportation Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	359	294.7
Transportation Assets [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Transportation Assets [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	149.1	121.3
Other Property, Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Other Property, Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	95.6	89.5
Estimated useful life	0 years
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$399	$702.80
Estimated useful life	0 years

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in aggregate asset retirement obligations [Roll Forward]
Beginning of period	$50.50	$45.20	$42.30
Change in cash flow estimate	2.1	1.4	-1
Accretion expense	4.4	3.9	3.9
Retirement of ARO	-0.2	0	0
End of period	$56.80	$50.50	$45.20

Investment_in_Unconsolidated_A2

Investment in Unconsolidated Affiliate (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Beginning of period	$55.90
Equity earnings	18		14.8		1.9
End of period	50.2		55.9
Return of capital from unconsolidated affiliate	5.7		0		0.5
Gulf Coast Fractionators LP [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)	38.80%		38.80%		38.80%
Beginning of period	55.9		53.1		36.7
Equity earnings	18		14.8		1.9
Cash distributions	-23.7	[1]	-12	[1]	-2.3	[1]
Cash calls for expansion projects	0		0		16.8
End of period	50.2		55.9		53.1
Return of capital from unconsolidated affiliate	$5.70				$0.50
[1]	Includes $5.7 million and $0.5 million distributions received in excess of our share of cumulative earnings for the years ended December 31, 2014 and 2012. Such excess distributions are considered a return of capital and are disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts_Payable_and_Accrued_L2

Accounts Payable and Accrued Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$416.70	$529.70
Other goods and services	108.9	124.7
Interest	37.3	35.9
Compensation and benefits	1.3	1.3
Income and other taxes	13.6	10.9
Other	14.9	18.7
Accounts payable and accrued liabilities	$592.70	$721.20

Debt_Obligations_Details

Debt Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt	$2,783.40		$2,905.30
Total Debt	2,966.20		2,905.30
Letters of credit outstanding	44.1	[1]	86.8	[1]
Scheduled maturities of debt [Abstract]
Total	2,991.40
2015	182.8
2016	0
2017	0
2018	0
2019	800
After 2019	2,008.60
Secured Debt [Member]
Scheduled maturities of debt [Abstract]
Total	0
2015	0
2016	0
2017	0
2018	0
2019	0
After 2019	0
Unsecured Debt [Member]
Scheduled maturities of debt [Abstract]
Total	2,808.60
2015	0
2016	0
2017	0
2018	0
2019	800
After 2019	2,008.60
Accounts Receivable Securitization Facility [Member]
Scheduled maturities of debt [Abstract]
Total	182.8
2015	182.8
2016	0
2017	0
2018	0
2019	0
After 2019	0
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred, minimum (in hundredths)	0.90%
Range of interest rates incurred, maximum (in hundredths)	0.90%
Weighted average interest rate incurred (in hundredths)	0.90%
Accounts Receivable Securitization Facility due December 2015 [Member] | Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Current debt	182.8	[1]	0	[1]
Maturity date	31-Dec-15
TRC Senior Secured Revolving Credit Facility due 2017 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	0	[2]	395	[2]
Maturity date	31-Oct-17
Line of credit facility, maximum borrowing capacity	1,200
Availability of credit under senior secured credit facility	1,155.90
Senior Unsecured 7 7/8% Notes due October 2018 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	0	[3]	250	[3]
Maturity date	15-Oct-18
Interest rate on fixed rate debt (in hundredths)	7.88%
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	483.6		483.6
Unamortized discount	-25.2		-28
Maturity date	1-Feb-21
Interest rate on fixed rate debt (in hundredths)	6.88%
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	6.88%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	300		300
Maturity date	1-Aug-22
Interest rate on fixed rate debt (in hundredths)	6.38%
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	6.38%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	600		600
Maturity date	1-May-23
Interest rate on fixed rate debt (in hundredths)	5.25%
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	5.25%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	625		625
Maturity date	15-Nov-23
Interest rate on fixed rate debt (in hundredths)	4.25%
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	4.25%
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt	800		0
Maturity date	15-Nov-19
Interest rate on fixed rate debt (in hundredths)	4.13%
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	4.13%
Senior Secured Credit Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred, minimum (in hundredths)	1.90%
Range of interest rates incurred, maximum (in hundredths)	4.50%
Weighted average interest rate incurred (in hundredths)	2.00%
Accounts Receivable Securitization Facility Due December 2014 [Member] | Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Long-term debt	$0	[1]	$279.70	[1]
Maturity date	31-Dec-14
[1]	The classification of the Securitization Facility as of December 31, 2014 has changed. The outstanding amounts under the Securitization Facility as of December 31, 2013 were reflected as long-term debt in our consolidated balance sheets because we had the ability and intent to fund the Securitization Facility's borrowings on a long-term basis. As of December 31, 2013, we intended to fund the Securitization Facility's borrowings either by further extending the termination date of the Securitization Facility or by utilizing the availability under our Senior Secured Revolving Credit Facility. As of December 31, 2014, we intended to fund the Securitization Facility's borrowings solely through further extensions of the termination date of the Securitization Facility; based on our history of extending the Securitization Facility, most recently through the Third Amendment to the Securitization Facility entered into in December 2014. As a result, all amounts outstanding under the Securitization Facility as of December 31, 2014 are reflected as a current liability in our consolidated balance sheets.
[2]	As of December 31, 2014, availability under our $1.2 billion senior secured revolving credit facility was $1,155.9 million.
[3]	The outstanding balance of the 7.875% Notes was redeemed in November 2014. See "Senior Unsecured Notes" below.

Debt_Obligations_Revolving_Cre

Debt Obligations, Revolving Credit Agreement (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012	Oct. 31, 2012	Sep. 30, 2012
Revolving Credit Facility [Member] | TRP Revolver [Member]
Revolving Credit Agreement [Abstract]
Maximum borrowing capacity	$1,200		$1,200	$1,100
Maturity date	3-Oct-17
Additional commitment increase available upon request	300		300
Maximum consolidated leverage ratio	5.5
Minimum ratio of consolidated EBITDA to consolidated interest expense	2.25
Revolving Credit Facility [Member] | TRP Revolver [Member] | Minimum [Member]
Revolving Credit Agreement [Abstract]
Commitment fee percentage (in hundredths)	0.30%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Maximum [Member]
Revolving Credit Agreement [Abstract]
Commitment fee percentage (in hundredths)	0.50%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Federal Funds Rate [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	0.50%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Base Rate [Member] | Minimum [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	0.75%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Base Rate [Member] | Maximum [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	1.75%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Eurodollar [Member] | Minimum [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	1.75%
Revolving Credit Facility [Member] | TRP Revolver [Member] | Eurodollar [Member] | Maximum [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	2.75%
Revolving Credit Facility [Member] | TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) [Member]
Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	1.00%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]
Revolving Credit Agreement [Abstract]
Maturity date	31-Jul-15
Debt issue costs written off		$1.70
Letters of Credit [Member] | TRP Revolver [Member] | Minimum [Member]
Revolving Credit Agreement [Abstract]
Interest rate percentage (in hundredths)	1.75%
Letters of Credit [Member] | TRP Revolver [Member] | Maximum [Member]
Revolving Credit Agreement [Abstract]
Interest rate percentage (in hundredths)	2.75%

Debt_Obligations_Senior_Unsecu

Debt Obligations, Senior Unsecured Notes (Details) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Jan. 31, 2012

Oct. 31, 2012

31-May-13

Nov. 30, 2012

Oct. 31, 2014

Nov. 30, 2014

The Partnership's Senior Unsecured Notes [Abstract]

Payment for redemption of debt

$259.80

$183.20

$217.70

Unsecured Debt [Member] | Senior Unsecured 11 1/4% Notes due July 2017 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Premium paid on redemption of debt

4.1

Unamortized debt issue costs written off

1

Payment for redemption of debt

76.8

Pretax gain (loss) on extinguishment of debt

-7.4

Unsecured Debt [Member] | Senior Unsecured 7 7/8% Notes due October 2018 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Redemption price, percentage of face value (in hundredths)

103.94%

Premium paid on redemption of debt

9.9

Unamortized debt issue costs written off

2.5

Pretax gain (loss) on extinguishment of debt

-12.4

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Due date

15-Oct-18

Unsecured Debt [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Issue date

1-Feb-11

Per annum interest rate (in hundredths)

6.88%

Due date

1-Feb-21

Dates interest paid

February & August 1st

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

90 days

Redemption Dates and Prices [Abstract]

Any Date Prior To

1-Feb-14

Price (in hundredths)

106.88%

Unsecured Debt [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2016 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

103.44%

Unsecured Debt [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2017 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

102.29%

Unsecured Debt [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2018 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

101.15%

Unsecured Debt [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2019 and Thereafter [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.00%

Unsecured Debt [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Aggregate principal amount issued

400

Net proceeds from private placement of notes

395.5

Premium paid on redemption of debt

6.4

Unamortized debt issue costs written off

1

Payment for redemption of debt

106.4

Face amount of notes redeemed

100

Pretax gain (loss) on extinguishment of debt

-7.4

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Issue date

1-Jan-12

Per annum interest rate (in hundredths)

6.38%

Due date

1-Aug-22

Dates interest paid

February & August 1st

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

180 days

Redemption Dates and Prices [Abstract]

Any Date Prior To

1-Feb-15

Price (in hundredths)

106.38%

Unsecured Debt [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2017 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

103.19%

Unsecured Debt [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2018 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

102.13%

Unsecured Debt [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2019 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

101.06%

Unsecured Debt [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2020 and Thereafter [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.00%

Unsecured Debt [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Aggregate principal amount issued

200

400

Percentage of face amount issued (in hundredths)

101.00%

99.50%

Gross proceeds from issuance of notes

202

398

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Issue date

Oct / Dec 2012

Per annum interest rate (in hundredths)

5.25%

Due date

1-May-23

Dates interest paid

May & November 1st

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

180 days

Redemption Dates and Prices [Abstract]

Any Date Prior To

1-Nov-15

Price (in hundredths)

105.25%

Unsecured Debt [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2017 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

102.63%

Unsecured Debt [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2018 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

101.75%

Unsecured Debt [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2019 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.88%

Unsecured Debt [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2020 and Thereafter [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.00%

Unsecured Debt [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Aggregate principal amount issued

625

Net proceeds from private placement of notes

618.1

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Issue date

1-May-13

Per annum interest rate (in hundredths)

4.25%

Due date

15-Nov-23

Dates interest paid

May & November 15th

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

180 days

Redemption Dates and Prices [Abstract]

Any Date Prior To

15-May-16

Price (in hundredths)

104.25%

Unsecured Debt [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2018 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

102.13%

Unsecured Debt [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2019 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

101.42%

Unsecured Debt [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2020 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.71%

Unsecured Debt [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2021 and Thereafter [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.00%

Unsecured Debt [Member] | Senior Unsecured 8 1/4% Notes due July 2016 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Redemption price, percentage of face value (in hundredths)

104.13%

Premium paid on redemption of debt

8.6

Unamortized debt issue costs written off

2.5

Unsecured Debt [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

Aggregate principal amount issued

800

Net proceeds from private placement of notes

$790.80

Terms of the Senior Unsecured Notes Outstanding [Abstract]

Issue date

1-Oct-14

Per annum interest rate (in hundredths)

4.13%

Due date

15-Nov-19

Dates interest paid

May & November 15th

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

180 days

Redemption Dates and Prices [Abstract]

Any Date Prior To

15-Nov-19

Price (in hundredths)

104.13%

Unsecured Debt [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | 2016 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

102.06%

Unsecured Debt [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | 2017 [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

101.03%

Unsecured Debt [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | 2018 and Thereafter [Member]

Redemption Dates and Prices [Abstract]

Price (in hundredths)

100.00%

Debt_Obligations_Accounts_Rece

Debt Obligations, Accounts Receivable Securitization Facility and Shelf Registration Statements (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Jul. 31, 2013
	Subsidiary
Debt Instrument [Line Items]
Aggregate amount of debt or equity securities allowed under shelf agreement	$300
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	300
Funding under securitization facility	182.8
Number of consolidated subsidiaries selling or contributing receivables under Securitization Facility	2
July 2013 Shelf [Member]
Debt Instrument [Line Items]
Aggregate amount of debt or equity securities allowed under shelf agreement		$800

Debt_Obligations_Debt_Reacquis

Debt Obligations, Debt Re-acquisitions Summary (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Re-acquisitions Summary [Abstract]
Loss on debt redemption	$12.40	$14.70	$12.80
Unsecured Debt [Member] | Notes 6.375% Redemption Date [Member]
Debt Re-acquisitions Summary [Abstract]
Premium over face value paid upon redemption	0	6.4	0
Write-off of deferred debt issue cost	0	1	0
Unsecured Debt [Member] | Notes 7.875% Redemption Date [Member]
Debt Re-acquisitions Summary [Abstract]
Premium over face value paid upon redemption	9.9	0	0
Write-off of deferred debt issue cost	2.5	0	0
Unsecured Debt [Member] | Notes 8.25% Redemption Date [Member]
Debt Re-acquisitions Summary [Abstract]
Premium over face value paid upon redemption	0	0	8.6
Write-off of deferred debt issue cost	0	0	2.5
Unsecured Debt [Member] | Notes 11.25% Redemption Date [Member]
Debt Re-acquisitions Summary [Abstract]
Premium over face value paid upon redemption	0	4.1	0
Recognition of unamortized discount	0	2.2	0
Write-off of deferred debt issue cost	0	1	0
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]
Debt Re-acquisitions Summary [Abstract]
Write-off of deferred debt issue cost	$0	$0	$1.70

Debt_Obligations_Subsequent_Ev

Debt Obligations, Subsequent Event (Details) (5% Notes [Member], Subsequent Event [Member], USD $)	1 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2015
5% Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$1,100
Net proceeds from private placement of notes	$1,090.80

Partnership_Units_and_Related_2

Partnership Units and Related Matters (Details) (USD $)	3 Months Ended												12 Months Ended			1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 30, 2012	Jan. 31, 2012	Aug. 31, 2012	Mar. 31, 2013	Aug. 31, 2013	31-May-14	Jan. 31, 2015
Partnership Equity [Abstract]
Ownership interest in Partnership by general partner (in hundredths)													2.00%
Aggregate amount of debt or equity securities allowed to be issued under the shelf agreement	$300												$300
Number of days from end of each quarter by when cash is distributed to unitholders													45 days
Distributions Made to Members or Limited Partners [Abstract]
Date paid or to be paid	13-Feb-15	14-Nov-14	14-Aug-14	15-May-14	14-Feb-14	14-Nov-13	14-Aug-13	15-May-13	14-Feb-13	14-Nov-12	14-Aug-12	15-May-12
Distributions to limited partners	96.3	92.3	89.5	87.2	84	79.4	75.8	71.7	69	59.1	57.3	55.5
Distributions to general partners (Incentive)	38.4	36	33.7	31.7	29.5	26.9	24.6	22.1	20.1	16.1	14.4	12.7
Distributions to general partners (2%)	2.7	2.6	2.5	2.4	2.3	2.2	2	1.9	1.8	1.5	1.5	1.4
Total distributions to general and limited partners	137.4	130.9	125.7	121.3	115.8	108.5	102.4	95.7	90.9	76.7	73.2	69.6	493.8	397.3	285.8
Distributions per limited partner per unit (in dollars per unit)	$0.81	$0.80	$0.78	$0.76	$0.75	$0.73	$0.72	$0.70	$0.68	$0.66	$0.64	$0.62
Shelf Offering 2010 Shelf [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)																10,925,000	4,405,000
Per share price on public offering (in dollars per share)																$36	$38.30
Net proceeds from public offering																378.2	164.8
Number of common units purchased by Parent (in units)																	1,300,000
Aggregate value of common units purchased by Parent																	49.8
General partner contributed to maintain general partner ownership percentage																8	3.5
Ownership interest in Partnership by general partner (in hundredths)																2.00%	2.00%
Purchase price of acquisition																975.8
August 2012 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)																		2,420,046
Net proceeds from public offering																		94.8
General partner contributed to maintain general partner ownership percentage																		2
Ownership interest in Partnership by general partner (in hundredths)																		2.00%
Dollar amount of common units able to sell from Equity Distribution Agreement																		100
March 2013 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)																			4,204,751
Net proceeds from public offering																			197.5
General partner contributed to maintain general partner ownership percentage																			4.1
Ownership interest in Partnership by general partner (in hundredths)																			2.00%
Dollar amount of common units able to sell from Equity Distribution Agreement																			200
August 2013 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)																				4,259,641
Net proceeds from public offering																				225.6
General partner contributed to maintain general partner ownership percentage																				4.7
Ownership interest in Partnership by general partner (in hundredths)																				2.00%
Dollar amount of common units able to sell from Equity Distribution Agreement																				400
May 2014 EDA [Member]
Partnership Equity [Abstract]
Dollar amount of common units able to sell from Equity Distribution Agreement																					400
May 2014 EDA [Member] | Subsequent Event [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)																						284,137
Net proceeds from public offering																						13
General partner contributed to maintain general partner ownership percentage																						0.3
Ownership interest in Partnership by general partner (in hundredths)																						2.00%
August 2013 EDA and May 2014 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)													7,175,096
Net proceeds from public offering													408.4
General partner contributed to maintain general partner ownership percentage													8.4
Commissions to sales agents, maximum (in hundredths)													1.00%
Ownership interest in Partnership by general partner (in hundredths)													2.00%
August 2013 EDA and May 2014 EDA [Member] | Subsequent Event [Member]
Partnership Equity [Abstract]
General partner contribution settled amount																						$1

Earnings_per_Limited_Partner_U2

Earnings per Limited Partner Unit (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings per Limited Partner Unit [Abstract]
Net income	$114.70	$138.20	$120.90	$131.30	$115.60	$65	$32.70	$45.30	$505.10		$258.60		$203.20
Less: Net income attributable to noncontrolling interests									37.4		25.1		28.6
Net income attributable to Targa Resources Partners LP									467.7		233.5		174.6
Net income attributable to general partner									148.7		107.5		66.7
Net income attributable to limited partners	67.7	89.7	73	88.6	77.1	31.6	1.2	16.1	319		126		107.9
Net income attributable to Targa Resources Partners LP									$467.70		$233.50		$174.60
Weighted average units outstanding - basic (in shares)									114,700,000		105,500,000		90,100,000
Net income available per limited partner unit - basic (in dollars per share)	$0.58	$0.78	$0.64	$0.79	$0.70	$0.30	$0.01	$0.16	$2.78		$1.19		$1.20
Weighted average units outstanding (in shares)									114,700,000		105,500,000		90,100,000
Dilutive effect of unvested stock awards (in shares)									400,000		200,000		100,000
Weighted average units outstanding - diluted (in shares)									115,100,000	[1]	105,700,000	[1]	90,200,000	[1]
Net income available per limited partner unit - diluted (in dollars per share)	$0.58	$0.78	$0.64	$0.78	$0.70	$0.30	$0.01	$0.16	$2.77		$1.19		$1.20
Anti-dilutive common unit excluded from the computation of diluted earnings (in shares)									168,495
[1]	For the year ended December 31, 2014, approximately 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities (Details) (Swaps [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
Natural Gas [Member] | Year 2015 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day)	55,551
Natural Gas [Member] | Year 2016 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day)	30,500
Natural Gas [Member] | Year 2017 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day)	5,000
NGL [Member] | Year 2015 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	1,210
NGL [Member] | Year 2016 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
NGL [Member] | Year 2017 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Condensate [Member] | Year 2015 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	1,500
Condensate [Member] | Year 2016 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	1,000
Condensate [Member] | Year 2017 [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	500

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, By Derivative Contract Type (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative assets	$60.20	$5.10
Derivative liabilities	5.2	9.4
Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	44.4	2
Long-term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	15.8	3.1
Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	5.2	8
Long-term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1.4
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	60.2	5.1
Derivative liabilities	0	9.1
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	44.4	2
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	15.8	3.1
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	7.7
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1.4
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Derivative liabilities	5.2	0.3
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$5.20	$0.30

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Asset [Abstract]
Pro forma net presentation, asset	$55
Gross asset	60.2	5.1
Pro forma net presentation, asset, total	55.8	2.5
Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	35.5
Gross liability	4.4
Pro forma net presentation, asset	31.1	3
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	24.7	2.5
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	44.4	2
Pro forma net presentation, asset, current	40	0.1
Current Position [Member] | Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	35.5
Gross liability	4.4
Pro forma net presentation, asset	31.1
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	8.9	0.1
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	15.8	3.1
Pro forma net presentation, asset, noncurrent	15.8	2.4
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	$15.80	$2.40

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Liability [Abstract]
Pro forma net presentation, liability	$55
Gross liability	5.2	9.4
Pro forma net presentation, liability, total	0.8	6.8
Counterparties with Offsetting Position [Member]
Derivative Liability [Abstract]
Gross asset		2.6
Gross liability		5.6
Pro forma net presentation, liability	31.1	3
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0.8	3.8
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	5.2	8
Pro forma net presentation, liability, current	0.8	6.1
Current Position [Member] | Counterparties with Offsetting Position [Member]
Derivative Liability [Abstract]
Gross asset		1.9
Gross liability		4.4
Pro forma net presentation, liability		2.5
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0.8	3.6
Long-term Position [Member]
Derivative Liability [Abstract]
Gross liability	0	1.4
Pro forma net presentation, liability, noncurrent	0	0.7
Long-term Position [Member] | Counterparties with Offsetting Position [Member]
Derivative Liability [Abstract]
Gross asset	0	0.7
Gross liability	0	1.2
Pro forma net presentation, liability	0	0.5
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	$0	$0.20

Derivative_Instruments_and_Hed6

Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Net gains on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months	$44.30
Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Deferred gains (losses) included in accumulated OCI	0		-2.4
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Deferred gains (losses) included in accumulated OCI	60.3	[1]	-3.7	[1]
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	-6.6		15.1		36
Cash Flow Hedging [Member] | Interest Expense, Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	-2.4		-6.1		-7.9
Cash Flow Hedging [Member] | Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	-4.2		21.2		43.9
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	59.8		-5.8		76.4
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives	($5.50)		($0.10)		$0.70
[1]	Includes deferred net gains of $44.3 million related to contracts that will be settled and reclassified to revenue over the next 12 months.

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]
Derivatives financial instruments, fair value, net	$55
Derivative fair value of net asset if commodity price increases by 10 percent	38.3
Derivative fair value of net asset if commodity price decreases by 10 percent	71.9
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	55.8		2.5
Liability from commodity derivative contracts	0.8		6.8
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Number of natural gas basis swaps categorized as Level 3	5
Contingent consideration			50
Commodity Derivative Contracts (Asset)/Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in the fair value hierarchy [Roll Forward]
Balance, beginning of period	-0.7		0.6	0
Change in valuation of contingent liability included in Other Income			0	0
Settlements included in Revenue	-0.2		-1.3	-0.1
Unrealized losses (gains) included in OCI	-1.1			0.7
Transfers out of Level 3	0.3
Balance, end of period	-1.7		-0.7	0.6
Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in the fair value hierarchy [Roll Forward]
Balance, beginning of period	0		15.3	0
Change in valuation of contingent liability included in Other Income			-15.3	15.3
Settlements included in Revenue	0		0	0
Unrealized losses (gains) included in OCI				0
Transfers out of Level 3	0
Balance, end of period	0		0	15.3
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	60.2	[1]	5.1
Liability from commodity derivative contracts	5.2	[1]	9.4
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	72.3		57.5
Carrying Value [Member] | Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		395
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	2,783.40		2,230.60
Carrying Value [Member] | Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	182.8		279.7
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	60.2	[1]	5.1
Liability from commodity derivative contracts	5.2	[1]	9.4
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	72.3		57.5
Fair Value [Member] | Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		395
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	2,731.50		2,253.50
Fair Value [Member] | Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	182.8		279.7
Fair Value [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	0	[1]	0
Liability from commodity derivative contracts	0	[1]	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	0		0
Fair Value [Member] | Level 1 [Member] | Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		0
Fair Value [Member] | Level 1 [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		0
Fair Value [Member] | Level 1 [Member] | Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	182.8		0
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	58.4	[1]	3.4
Liability from commodity derivative contracts	5.1	[1]	8.4
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	0		0
Fair Value [Member] | Level 2 [Member] | Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		395
Fair Value [Member] | Level 2 [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	2,731.50		2,253.50
Fair Value [Member] | Level 2 [Member] | Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		279.7
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	1.8	[1]	1.7
Liability from commodity derivative contracts	0.1	[1]	1
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	0		0
Fair Value [Member] | Level 3 [Member] | Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		0
Fair Value [Member] | Level 3 [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		0
Fair Value [Member] | Level 3 [Member] | Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	$0
[1]	The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	3 Months Ended												12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of transactions with Targa [Abstract]
Cash distributions to Targa based on unit ownership	$2.70	$2.60	$2.50	$2.40	$2.30	$2.20	$2	$1.90	$1.80	$1.50	$1.50	$1.40
Cash contributions from Targa to maintain its 2% general partner ownership													7.7	10.8	11.5
General partner interest (in hundredths)													2.00%
Targa Resources Corp. [Member]
Summary of transactions with Targa [Abstract]
Targa billings of payroll and related costs included in operating expense													124.9	109.7	97.2
Targa allocation of general & administrative expense													129.4	134.3	124
Cash distributions to Targa based on unit ownership													180.7	138.2	92.7
Cash contributions from Targa to maintain its 2% general partner ownership													7.7	10.8	11.5
Purchase of common units by Targa													0	0	49.8
General partner interest (in hundredths)													2.00%
GCF [Member]
Summary of transactions with Targa [Abstract]
Revenues													0.8	0.4	0.1
Cost and expenses													$7.60	$6.30	$1.90

Commitments_Leases_Details

Commitments (Leases) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract]
In Aggregate	$38.40
2015	9.7
2016	9.4
2017	7.9
2018	6.4
2019	5
Operating Leases [Member]
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract]
In Aggregate	28.9	[1]
2015	7.7	[1]
2016	7.4	[1]
2017	5.9	[1]
2018	4.6	[1]
2019	3.3	[1]
Total expenses incurred under lease obligations [Abstract]
Expenses on lease obligations	24.4	[2]	23.3	[2]	16.1	[2]
Land Site Lease and Right-of-Way [Member]
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract]
In Aggregate	9.5	[3]
2015	2	[3]
2016	2	[3]
2017	2	[3]
2018	1.8	[3]
2019	1.7	[3]
Total expenses incurred under lease obligations [Abstract]
Expenses on lease obligations	$4.10		$3.60		$3.30
[1]	Includes minimum payments on lease obligations for office space, railcars and tractors.
[2]	Includes short-term leases for items such as compressors and equipment.
[3]	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.

Contingencies_Details

Contingencies (Details)	12 Months Ended	3 Months Ended	2 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Nov. 30, 2014
	Defendant	Unitholder	Unitholder
Targa Shareholder Litigation [Member]
Loss Contingencies [Line Items]
Number of defendants who have been served	2
Atlas Unitholder Litigation [Member] | Atlas Pipeline Partners [Member]
Loss Contingencies [Line Items]
Number of public unitholders who filed lawsuits		5
Atlas Unitholder Litigation [Member] | Atlas Energy [Member]
Loss Contingencies [Line Items]
Number of public unitholders who filed lawsuits			2

Significant_Risks_and_Uncertai2

Significant Risks and Uncertainties (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Risks and Uncertainties [Abstract]
Reduction of maximum loss due to counterparty credit risk by master netting provision	$4.40
Potential minimum loss attributable to individual counterparties	3.3
Potential maximum loss attributable to individual counterparties	27.5
Allowance for Bad Debts [Member]
Summary of activity affecting allowance for bad debts [Roll Forward]
Balance at beginning of year	0.9	0.7	2.2
Additions	0	0.2	0
Deductions	-0.9	0	-1.5
Balance at end of year	$0	$0.90	$0.70
Customer Concentration Risk [Member] | Consolidated Revenues [Member] | Chevron Phillips Chemical Company LLC [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	4.00%	8.00%	10.00%

Other_Operating_Income_Expense2

Other Operating (Income) Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Operating (Income) Expense [Abstract]
Loss (gain) on sale or disposal of assets	($4.80)	$3.90	$15.60	[1]
Casualty loss	0.1	4.3	3.6
Miscellaneous business tax	0.4	0.7	0.7
Other	1.3	0.7	0
Other Operating (Income) Expense	-3	9.6	19.9
Loss due to write-off of investment			$15.40
[1]	Includes a $15.4 million loss in 2012 due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Cash:
Interest paid, net of capitalized interest	$131	[1]	$119.10	[1]	$92.50	[1]
Income taxes paid, net of refunds	2.7		2.3		2.3
Non-cash:
Deadstock inventory transferred to property, plant and equipment	14.8		30.4		3
Badlands contingent consideration recorded at acquisition date	0		0		15.3
Accrued distribution equivalent rights	1.4		1.7		0.5
Change in receivables from unit offerings	1		0		0
Change in capital accruals	19		-0.4		-34.4
Transfers from materials and supplies inventory to property, plant and equipment	4.6		20.5		0
Change in ARO cash flow estimate	2.1		1.4		-1
Interest capitalized on major projects	$16.10		$28		$13.60
[1]	Interest capitalized on major projects was $16.1 million, $28.0 million and $13.6 million for 2014, 2013 and 2012.

Compensation_Plans_Details

Compensation Plans (Details) (USD $)	0 Months Ended			12 Months Ended						0 Months Ended		1 Months Ended
In Millions, except Share data, unless otherwise specified	Aug. 22, 2014	Aug. 01, 2014	Feb. 14, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Jan. 12, 2015	Jan. 21, 2015	Jan. 31, 2015
Weighted average grant-date fair value [Abstract]
Vesting percentage of IPO stock awards over 24 months (in hundredths)						60.00%
Vesting percentage of IPO stock awards in year three (in hundredths)						40.00%
Stock repurchased from employees (in shares)	1,006	12,849	8,113			169,159		197,731
Stock repurchase price (in dollars per share)	$137.64	$129.46	$96.52			$79.01		$47.88
401(k) Plan [Abstract]
Description of 401(k) plan				Targa has a 401(k) plan whereby it matches 100% of up to 5% of an employeebs contribution (subject to certain limitations in the plan). Targa also contributes an amount equal to 3% of each employeebs eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $10.5 million, $9.6 million and $8.7 million during 2014, 2013 and 2012.
Employer matching contribution percent (in hundredths)				100.00%
Maximum annual contribution per employee percent (in hundredths)				5.00%
Contribution per employee percent (in hundredths)				3.00%
Contributions to defined contribution plan				$10.50		$9.60		$8.70
Subsequent Event [Member]
Weighted average grant-date fair value [Abstract]
Stock repurchased from employees (in shares)										5,930
Stock repurchase price (in dollars per share)										$89.27
Equity-Settled Performance Units [Member]
Weighted average grant-date fair value [Abstract]
To be recognized in future periods				14.1
Compensation expenses recognized				8.8		5.5		3.1
Unrecognized compensation expenses				14.1
Weighted average recognition period for unrecognized compensation cost				2 years
Fair value of units vested during the period				10		0		0
Equity-Settled Performance Units [Member] | Subsequent Event [Member]
Nonvested, number of units/ shares [Roll Forward]
Granted (in shares)											103,760
Cash-Settled Performance Units [Member]
Weighted average grant-date fair value [Abstract]
Compensation expenses recognized				11		21.9		14.2
Weighted average recognition period for unrecognized compensation cost				1 year 8 months 12 days
Fair value of units vested during the period				14.7		25.2		22.2
Accrued Distribution Equivalent Rights Settled [Member]
Weighted average grant-date fair value [Abstract]
Fair value of units vested during the period				1.6		0		0
Director Grants [Member]
Weighted average grant-date fair value [Abstract]
Compensation expenses recognized				0.4		0.5		0.5
Fair value of units vested during the period				0.4		0.7		1
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total units authorized (in shares)				5,000,000
Weighted average grant-date fair value [Abstract]
Recognized tax benefits				1		1.6		1.3
Accrued Dividends Settled [Member]
Weighted average grant-date fair value [Abstract]
Fair value of units vested during the period				0.5		2.4		2
Partnership Long-term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total units authorized (in shares)				1,680,000
Vesting period				3 years
Partnership Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				412,290
Granted (in shares)				122,950
Vested/ Vested and paid (in shares)				-123,570
Forfeited (in shares)				-8,740
Outstanding, end of period (in shares)				402,930
Weighted average grant-date fair value [Abstract]
Calculated fair market value as of period end				19
Current liability				7.3
Long-term liability				3.6
Liability as of year end				10.9
To be recognized in future periods				8.1
Unrecognized compensation expenses				8.1
Partnership Long-term Incentive Plan [Member] | Director Grants [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				0		4,500		19,831
Granted (in shares)				8,740		12,780		9,980
Vested/ Vested and paid (in shares)				-8,740		-17,280		-25,311
Outstanding, end of period (in shares)				0		0		4,500
Weighted average grant-date fair value [Abstract]
Outstanding, beginning of period (in dollars per share)				$0		$23.51		$16.31
Granted (in dollars per share)				$50.29		$39.33		$38.72
Vested and paid (in dollars per share)				$50.29		$35.21		$23.86
Outstanding, end of period (in dollars per share)				$0		$0		$23.51
Partnership Long-term Incentive Plan [Member] | Director Grants [Member] | Non-Management Directors [Member] | Subsequent Event [Member]
Nonvested, number of units/ shares [Roll Forward]
Granted (in shares)											10,565
Weighted average grant-date fair value [Abstract]
Units granted per individual (in units)											2,113
2010 Long Term Incentive Plan [Member] | Restricted Stock [Member]
Weighted average grant-date fair value [Abstract]
To be recognized in future periods				1.1
Compensation expenses recognized				2.2		6.3		13.7
Unrecognized compensation expenses				1.1
Weighted average recognition period for unrecognized compensation cost				0 years 10 months 24 days
2010 Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Weighted average grant-date fair value [Abstract]
To be recognized in future periods				7
Compensation expenses recognized				2.5		0.4		0
Unrecognized compensation expenses				7
Weighted average recognition period for unrecognized compensation cost				2 years 3 months 18 days
2011 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				124,870
Granted (in shares)				0
Vested/ Vested and paid (in shares)				-123,570
Forfeited (in shares)				-1,300
Outstanding, end of period (in shares)				0
2012 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				142,460
Granted (in shares)				0
Vested/ Vested and paid (in shares)				0
Forfeited (in shares)				-4,000
Outstanding, end of period (in shares)				138,460
Weighted average grant-date fair value [Abstract]
Calculated fair market value as of period end				8.8
Current liability				7.3
Long-term liability				0
Liability as of year end				7.3
To be recognized in future periods				1.5
Vesting date				30-Jun-15
Unrecognized compensation expenses				1.5
2013 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				144,960
Granted (in shares)				0
Vested/ Vested and paid (in shares)				0
Forfeited (in shares)				-2,850
Outstanding, end of period (in shares)				142,110
Weighted average grant-date fair value [Abstract]
Calculated fair market value as of period end				6.5
Current liability				0
Long-term liability				3.1
Liability as of year end				3.1
To be recognized in future periods				3.4
Vesting date				30-Jun-16
Unrecognized compensation expenses				3.4
2014 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				0
Granted (in shares)				122,950
Vested/ Vested and paid (in shares)				0
Forfeited (in shares)				-590
Outstanding, end of period (in shares)				122,360
Weighted average grant-date fair value [Abstract]
Calculated fair market value as of period end				3.7
Current liability				0
Long-term liability				0.5
Liability as of year end				0.5
To be recognized in future periods				3.2
Vesting date				30-Jun-17
Unrecognized compensation expenses				3.2
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				203,973		711,030		1,434,220
Granted (in shares)				0		30,623	[1]	91,090	[1]
Vested/ Vested and paid (in shares)				-82,800	[2]	-534,940	[3]	-805,350	[3]
Forfeited (in shares)				-1,980		-2,740		-8,930
Outstanding, end of period (in shares)				119,193		203,973		711,030
Weighted average grant-date fair value [Abstract]
Outstanding, beginning of period (in dollars per share)				$41.05		$25.95		$22.67
Granted (in dollars per share)				$0		$57.59	[1]	$42.50	[1]
Vested and paid (in dollars per share)				$33.37	[2]	$22	[3]	$22	[3]
Forfeited (in dollars per share)				$42.82		$27.28		$23.99
Outstanding, end of period (in dollars per share)				$46.35		$41.05		$25.95
Fair value of units vested during the period				$7.10	[4]	$42.20	[4]	$40.30	[4]
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Nonvested, number of units/ shares [Roll Forward]
Outstanding, beginning of period (in shares)				55,550		0
Granted (in shares)				54,357		55,790
Vested/ Vested and paid (in shares)				-100
Forfeited (in shares)				-1,440		-240
Outstanding, end of period (in shares)				108,367		55,550
Weighted average grant-date fair value [Abstract]
Outstanding, beginning of period (in dollars per share)				$69.92		$0
Granted (in dollars per share)				$112.89		$69.90
Vested and paid (in dollars per share)				$67.07
Forfeited (in dollars per share)				$75.81		$67.07
Outstanding, end of period (in dollars per share)				$91.41		$69.92
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member]
Nonvested, number of units/ shares [Roll Forward]
Granted (in shares)												32,372
[1]	These awards will cliff vest at the end of three years.
[2]	Targa repurchased 8,113, 12,849 and 1,006 shares from employees at $96.52, $129.46 and $137.64 per share on February 14th, August 1st , and August 22nd of 2014 to satisfy the employees' minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded in treasury stock at cost
[3]	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures. Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employees' minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded in treasury stock at cost.
[4]	Targa recognized $1.0 million, $1.6 million and $1.3 million in tax benefits for 2014, 2013 and 2012 that were associated with the vesting of the restricted stock.

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended									12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
										Segment
Segment Reporting Information [Line Items]
Number of divisions										2
Sales of commodities										$7,595.20		$5,728.20	$5,319
Fees from midstream services										1,021.30		586.7	357.9
Revenues	2,032.90		2,288.30	2,000.60	2,294.70	2,104.50	1,466.10	1,370.50	1,373.80	8,616.50		6,314.90	5,676.90
Operating margin										1,136.60		801.5	691.7
Other financial information [Abstract]
Total assets	6,377.20	[1]				5,971.40				6,377.20	[1]	5,971.40	5,025.70
Capital expenditures										747.8		1,034.50	616.7
Business acquisitions										0		0	996.2
Gathering and Processing [Member]
Segment Reporting Information [Line Items]
Number of reportable segments per division										2
Field Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenues										1,884.10		1,525	1,364.20
Operating margin										372.3		270.5	231.2
Coastal Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenues										967		981.8	965.4
Operating margin										77.6		85.4	115.1
Logistics and Marketing [Member]
Segment Reporting Information [Line Items]
Number of reportable segments per division										2
Logistics Assets [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenues										705.4		536.9	463.4
Operating margin										445.1		282.3	188.3
Marketing and Distribution [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenues										7,971.50		5,804.10	5,401.40
Operating margin										249.6		141.9	116
Other Segment [Member]
Segment Reporting Information [Line Items]
Revenues										-8		21.4	41.1
Operating margin										-8		21.4	41.1
Other financial information [Abstract]
Total assets	60.2	[1]				5.1				60.2	[1]	5.1	34.4
Capital expenditures										0		0	0
Business acquisitions													0
Corporate and Elimination [Member]
Segment Reporting Information [Line Items]
Revenues										-2,903.50		-2,554.30	-2,558.60
Operating margin										0		0	0
Other financial information [Abstract]
Total assets	115	[1]				122.1				115	[1]	122.1	129.8
Capital expenditures										6.1		5.1	13.9
Business acquisitions													0
Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										7,595.20		5,728.20	5,319
Fees from midstream services										1,021.30		586.7	357.9
Revenues										8,616.50		6,314.90	5,676.90
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										197.4		188.8	172.7
Fees from midstream services										190.3		113.9	39.5
Revenues										387.7		302.7	212.2
Other financial information [Abstract]
Total assets	3,409	[1]				3,200.70				3,409	[1]	3,200.70	2,797.90
Capital expenditures										423.1		557.8	222.1
Business acquisitions													970.4
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										355		305	240.6
Fees from midstream services										34.4		33.6	23.6
Revenues										389.4		338.6	264.2
Other financial information [Abstract]
Total assets	367.2	[1]				383.8				367.2	[1]	383.8	414.1
Capital expenditures										14		20.6	9.4
Business acquisitions													25.8
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										99.1		140.5	184.4
Fees from midstream services										293.6		216	170.7
Revenues										392.7		356.5	355.1
Other financial information [Abstract]
Total assets	1,717.30	[1]				1,503.60				1,717.30	[1]	1,503.60	1,100.90
Capital expenditures										274.4		444.7	359
Business acquisitions													0
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										6,951.70		5,072.40	4,680.20
Fees from midstream services										503		223.3	124.2
Revenues										7,454.70		5,295.70	4,804.40
Other financial information [Abstract]
Total assets	708.5	[1]				756.1				708.5	[1]	756.1	548.6
Capital expenditures										30.2		6.3	12.3
Business acquisitions													0
Operating Segments [Member] | Other Segment [Member]
Segment Reporting Information [Line Items]
Sales of commodities										-8		21.4	41.1
Fees from midstream services										0		0	0
Revenues										-8		21.4	41.1
Operating Segments [Member] | Corporate and Elimination [Member]
Segment Reporting Information [Line Items]
Sales of commodities										0		0.1	0
Fees from midstream services										0		-0.1	-0.1
Revenues										0		0	-0.1
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sales of commodities										0		0	0
Fees from midstream services										0		0	0
Revenues										0		0	0
Intersegment Eliminations [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										1,491.20		1,218.90	1,150.70
Fees from midstream services										5.2		3.4	1.3
Revenues										1,496.40		1,222.30	1,152
Intersegment Eliminations [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										577.6		642.2	701.1
Fees from midstream services										0		1	0.1
Revenues										577.6		643.2	701.2
Intersegment Eliminations [Member] | Logistics Assets [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										4.4		3.9	1.8
Fees from midstream services										308.3		176.5	106.5
Revenues										312.7		180.4	108.3
Intersegment Eliminations [Member] | Marketing and Distribution [Member] | Reportable Segments [Member]
Segment Reporting Information [Line Items]
Sales of commodities										486.7		478.6	565
Fees from midstream services										30.1		29.8	32
Revenues										516.8		508.4	597
Intersegment Eliminations [Member] | Other Segment [Member]
Segment Reporting Information [Line Items]
Sales of commodities										0		0	0
Fees from midstream services										0		0	0
Revenues										0		0	0
Intersegment Eliminations [Member] | Corporate and Elimination [Member]
Segment Reporting Information [Line Items]
Sales of commodities										-2,559.90		-2,343.60	-2,418.60
Fees from midstream services										-343.6		-210.7	-139.9
Revenues										($2,903.50)		($2,554.30)	($2,558.50)
[1]	Corporate assets primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our long-term debt.

Segment_Information_Revenues_b

Segment Information, Revenues by Product and Service and Reconciliation of Operating Margin to Net Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue from External Customer [Line Items]
Sales of commodities									$7,595.20	$5,728.20	$5,319
Fees from midstream services									1,021.30	586.7	357.9
Total revenues	2,032.90	2,288.30	2,000.60	2,294.70	2,104.50	1,466.10	1,370.50	1,373.80	8,616.50	6,314.90	5,676.90
Reconciliation of operating margin to net income
Operating margin									1,136.60	801.5	691.7
Depreciation and amortization expense									-346.5	-271.6	-197.3
General and administrative expense									-139.8	-143.1	-131.6
Interest expense, net									-143.8	-131	-116.8
Other, net									3.4	5.7	-38.6
Income tax expense									-4.8	-2.9	-4.2
Net income	114.7	138.2	120.9	131.3	115.6	65	32.7	45.3	505.1	258.6	203.2
Natural Gas Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities									1,409.30	1,224.70	926.9
NGL Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities									5,960.10	4,224	4,055.70
Condensate Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities									134.3	121.8	114.1
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sales of commodities									96.3	136	180.1
Derivative settlements [Member]
Revenue from External Customer [Line Items]
Sales of commodities									-4.8	21.7	42.2
Fractionating and Treating Fees [Member]
Revenue from External Customer [Line Items]
Fees from midstream services									208.9	133.9	110.1
Storage, Terminaling, Transportation and Export Fees [Member]
Revenue from External Customer [Line Items]
Fees from midstream services									548.1	280.3	162.5
Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Fees from midstream services									196.9	114.1	45
Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services									$67.40	$58.40	$40.30

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Data (Unaudited) [Abstract]
Revenues	$2,032.90	$2,288.30	$2,000.60	$2,294.70	$2,104.50	$1,466.10	$1,370.50	$1,373.80	$8,616.50	$6,314.90	$5,676.90
Gross margin	398.2	407.8	384	379.6	355.1	297.1	265.2	260.3	1,569.60	1,177.70
Operating income	168.4	171.4	152.9	160.6	146.8	91	63.2	76.2	653.3	377.2	342.9
Net income	114.7	138.2	120.9	131.3	115.6	65	32.7	45.3	505.1	258.6	203.2
Net income allocable to limited partners	$67.70	$89.70	$73	$88.60	$77.10	$31.60	$1.20	$16.10	$319	$126	$107.90
Net income per limited partner unit [Abstract]
basic (in dollars per share)	$0.58	$0.78	$0.64	$0.79	$0.70	$0.30	$0.01	$0.16	$2.78	$1.19	$1.20
diluted (in dollars per share)	$0.58	$0.78	$0.64	$0.78	$0.70	$0.30	$0.01	$0.16	$2.77	$1.19	$1.20