Targa Resources (TRGP) 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	Feb. 06, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Targa Resources Corp.
Entity Central Index Key	1389170
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			$5,884
Entity Common Stock, Shares Outstanding		42,143,395
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$81		$66.70
Trade receivables, net of allowances of $0.0 million and $1.1 million	567.3		658.8
Inventories	168.9		150.7
Deferred income taxes	0.1		0.1
Assets from risk management activities	44.4		2
Other current assets	20.9		18.9
Total current assets	882.6		897.2
Property, plant and equipment	6,521.10		5,758.40
Accumulated depreciation	-1,696.50		-1,408.50
Property, plant and equipment, net	4,824.60		4,349.90
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	88.4		89.1
Total assets	6,453.50	[1]	6,048.60
Current liabilities:
Accounts payable and accrued liabilities	638.5		761.8
Accounts receivable securitization facility	182.8		0
Deferred income taxes	0.6		0.6
Liabilities from risk management activities	5.2		8
Total current liabilities	827.1		770.4
Long-term debt	2,885.40		2,989.30
Long-term liabilities from risk management activities	0		1.4
Deferred income taxes	138.2		135.5
Other long-term liabilities	63.3		60.7
Commitments and contingencies (see Notes 17 and 18)
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 300,000,000 shares authorized)	0		0
Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding)	0		0
Additional paid-in capital	164.9		151.6
Retained earnings	25.5		20.5
Accumulated other comprehensive income (loss)	4.8		-0.5
Treasury stock, at cost (388,890 shares as of December 31, 2014 and 366,890 as of December 31, 2013)	-25.4		-22.8
Total Targa Resources Corp. stockholders' equity	169.8		148.8
Noncontrolling interests in subsidiaries	2,369.70		1,942.50
Total owners' equity	2,539.50		2,091.30
Total liabilities and owners' equity	$6,453.50		$6,048.60
[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:
Trade receivables, allowances	$0	$1.10
Targa Resources Corp. stockholders' equity:
Common stock, par value (in dollars per share)	$0.00	$0.00
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares issued (in shares)	42,532,353	42,529,068
Common stock, shares outstanding (in shares)	42,143,463	42,162,178
Preferred stock, par value (in dollar per share)	$0.00	$0.00
Preferred stock, shares authorized (in shares)	100,000,000	100,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury Stock, shares (in shares)	388,890	366,890

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
CONDENSED STATEMENT OF OPERATIONS
Revenues	$8,616.50	$6,314.70	$5,679
Costs and expenses:
Product purchases	7,046.90	5,137.20	4,672.30
Operating expenses	433.1	376.3	313.1
Depreciation and amortization expenses	351	271.9	197.6
General and administrative expenses	148	151.5	139.8
Other operating (income) expense	-3	9.6	19.9
Income from operations	640.5	368.2	336.3
Other income (expense):
Interest expense, net	-147.1	-134.1	-120.8
Equity earnings	18	14.8	1.9
Gain (loss) on debt redemptions and amendments	-12.4	-14.7	-12.8
Other	-8	15.3	-8.4
Income before income taxes	491	249.5	196.2
Income tax (expense) benefit:
Current	-72.4	-42.8	-27.9
Deferred	4.4	-5.4	-9
Income tax expense total	-68	-48.2	-36.9
Net income	423	201.3	159.3
Less: Net income attributable to noncontrolling interests	320.7	136.2	121.2
Net income available to common shareholders	$102.30	$65.10	$38.10
Net income available per common share - basic (in dollars per share)	$2.44	$1.56	$0.93
Net income available per common share - diluted (in dollars per share)	$2.43	$1.55	$0.91
Weighted average shares outstanding - basic (in shares)	42	41.6	41
Weighted average shares outstanding - diluted (in shares)	42.1	42.1	41.8

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
Targa Resources Corp.
Net income attributable to common shareholders	$102.30	$65.10	$38.10
Commodity hedging contracts:
Change in fair value, pre-tax	7.5	-0.8	11.9
Change in fair value, related income tax	-2.9	0.3	-4.4
Change in fair value, after tax	4.6	-0.5	7.5
Settlement reclassified to revenues, pre-tax	0.6	-2.8	-9
Settlement reclassified to revenues, related income tax	-0.1	1.1	3.3
Settlement reclassified to revenues, after tax	0.5	-1.7	-5.7
Interest rate swaps:
Change in fair value, pre-tax	0	0	0
Change in fair value, related income tax	0	0	0
Change in fair value, after tax	0	0	0
Settlements reclassified to interest expense, net, pre-tax	0.3	0.8	1.3
Settlements reclassified to interest expense, net, related income tax	-0.1	-0.3	-0.6
Settlements reclassified to interest expense, net, after tax	0.2	0.5	0.7
Other comprehensive income (loss) attributable to Targa Resources Corp., pre-tax	8.4	-2.8	4.2
Other comprehensive income (loss) attributable to Targa Resources Corp., related income tax	-3.1	1.2	-1.7
Other comprehensive income (loss) attributable to Targa Resources Corp., after tax	5.3	-1.7	2.5
Comprehensive income attributable to Targa Resources Corp.	107.6	63.4	40.6
Noncontrolling interests
Net income attributable to noncontrolling interests	320.7	136.2	121.2
Commodity hedging contracts:
Change in fair value, pre-tax	52.2	-5	64.9
Change in fair value, related income tax	0	0	0
Change in fair value, after tax	52.2	-5	64.9
Settlement reclassified to revenues, pre-tax	3.6	-18.2	-37
Settlement reclassified to revenues, related income tax	0	0	0
Settlement reclassified to revenues, after tax	3.6	-18.2	-37
Interest rate swaps:
Change in fair value, pre-tax	0	0	0
Change in fair value, related income tax	0	0	0
Change in fair value, after tax	0	0	0
Settlements reclassified to interest expense, net, pre-tax	2.1	5.3	6.6
Settlements reclassified to interest expense, net, related income tax	0	0	0
Settlements reclassified to interest expense, net, after tax	2.1	5.3	6.6
Other comprehensive income (loss) attributable to noncontrolling interests, before tax	57.9	-17.9	34.5
Other comprehensive income (loss) attributable to noncontrolling interests, related income tax	0	0	0
Other comprehensive income (loss) attributable to noncontrolling interests, after tax	57.9	-17.9	34.5
Comprehensive income attributable to noncontrolling interests	378.6	118.3	155.7
Total
Net income	423	201.3	159.3
Commodity hedging contracts:
Change in fair value, pre-tax	59.7	-5.8	76.8
Change in fair value, related income tax	-2.9	0.4	-4.4
Change in fair value, after tax	56.8	-5.4	72.4
Settlement reclassified to revenues, pre-tax	4.2	-21	-46
Settlement reclassified to revenues, related income tax	-0.1	1.1	3.3
Settlement reclassified to revenues, after tax	4.1	-19.9	-42.7
Interest rate swap:
Change in fair value, pre-tax	0	0	0
Change in fair value, related income tax	0	0	0
Change in fair value, after tax	0	0	0
Settlements reclassified to interest expense, net, pre-tax	2.4	6.1	7.9
Settlements reclassified to interest expense, net, related income tax	-0.1	-0.3	-0.6
Settlements reclassified to interest expense, net, after tax	2.3	5.8	7.3
Other comprehensive income (loss), pre-tax	66.3	-20.7	38.7
Other comprehensive income (loss), related income tax	-3.1	1.2	-1.7
Other comprehensive income (loss), after tax	63.2	-19.6	37
Total comprehensive income	$486.20	$181.70	$196.30

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY (USD $)	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]	Noncontrolling Interest [Member]	Total
In Millions, except Share data, unless otherwise specified
Balance at Dec. 31, 2011	$0	$229.50	($70.10)	($1.30)	$0	$1,172.60	$1,330.70
Balance (in shares) at Dec. 31, 2011	42,398,000				0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	0	15.3	0	0	0	3.5	18.8
Compensation on equity grants (in shares)	95,000				0
Accrual of distribution equivalent rights	0	0	0	0	0	-0.5	-0.5
Common stock and Partnership units tendered for tax withholding obligations	0	0	0	0	-9.5	0	-9.5
Common stock and Partnership units tendered for tax withholding obligations (in shares)	-198,000				198,000
Sale of Partnership limited partner interests	0	0	0	0	0	493.5	493.5
Impact of Partnership equity transactions	0	5.2	0	0	0	-5.2	0
Dividends in excess of retained earnings	0	-64.4	0	0	0	0	-64.4
Distributions to non-controlling interests	0	-1.2	0	0	0	-210.3	-211.5
Other comprehensive income (loss)	0	0	0	2.5	0	34.5	37
Net income	0	0	38.1	0	0	121.2	159.3
Balance at Dec. 31, 2012	0	184.4	-32	1.2	-9.5	1,609.30	1,753.40
Balance (in shares) at Dec. 31, 2012	42,295,000				198,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	0	8.8	0	0	0	6	14.8
Compensation on equity grants (in shares)	0				0
Accrual of distribution equivalent rights	0	0	0	0	0	-1.7	-1.7
Shares issued under compensation program (in shares)	36,000
Common stock and Partnership units tendered for tax withholding obligations	0	0	0	0	-13.3	0	-13.3
Common stock and Partnership units tendered for tax withholding obligations (in shares)	-169,000				169,000
Sale of Partnership limited partner interests	0	0	0	0	0	517.7	517.7
Impact of Partnership equity transactions	0	32.7	0	0	0	-32.7	0
Dividends	0	0	-12.6	0	0	0	-12.6
Dividends in excess of retained earnings	0	-74.3	0	0	0	0	-74.3
Distributions to non-controlling interests	0	0	0	0	0	-274.4	-274.4
Other comprehensive income (loss)	0	0	0	-1.7	0	-17.9	-19.6
Net income	0	0	65.1	0	0	136.2	201.3
Balance at Dec. 31, 2013	0	151.6	20.5	-0.5	-22.8	1,942.50	2,091.30
Balance (in shares) at Dec. 31, 2013	42,162,000				367,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	0	6.1	0	0	0	9.2	15.3
Compensation on equity grants (in shares)	0				0
Accrual of distribution equivalent rights	0	0	0	0	0	-1.4	-1.4
Shares issued under compensation program (in shares)	3,000
Common stock and Partnership units tendered for tax withholding obligations	0	0	0	0	-2.6	-4.8	-7.4
Common stock and Partnership units tendered for tax withholding obligations (in shares)	-22,000				22,000
Sale of Partnership limited partner interests	0	0	0	0	0	408.4	408.4
Impact of Partnership equity transactions	0	23	0	0	0	-23	0
Dividends	0	0	-97.3	0	0	0	-97.3
Dividends in excess of retained earnings	0	-15.8	0	0	0	0	-15.8
Distributions to non-controlling interests	0	0	0	0	0	-339.8	-339.8
Other comprehensive income (loss)	0	0	0	5.3	0	57.9	63.2
Net income	0	0	102.3	0	0	320.7	423
Balance at Dec. 31, 2014	$0	$164.90	$25.50	$4.80	($25.40)	$2,369.70	$2,539.50
Balance (in shares) at Dec. 31, 2014	42,143,000				389,000

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	$423	$201.30	$159.30
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense	11.8	15.9	18.2
Compensation on equity grants	14.3	13.2	17.5
Depreciation and amortization expenses	351	271.9	197.6
Accretion of asset retirement obligations	4.5	4	4
Deferred income tax expense (benefit)	-4.4	5.4	9
Equity earnings of unconsolidated affiliate	-18	-14.8	-1.9
Distributions of unconsolidated affiliate	18	12	1.9
Risk management activities	4.7	-0.3	3.6
(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	90.2	-143.6	98
Inventory	-36.2	-84.5	6
Accounts payable and other liabilities	-104.7	83.6	-113.4
Net cash provided by operating activities	761.8	382.7	428.2
Cash flows from investing activities
Outlays for property, plant and equipment	-762.2	-1,013.60	-582.7
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	4.5
Net cash used in investing activities	-751.4	-1,026.30	-1,590.70
Partnership loan facilities:
Proceeds	2,400	2,238	2,595
Repayments	-2,254.80	-2,021.20	-1,690.70
Partnership accounts receivable securitization facility:
Proceeds	381.9	373.3	0
Repayments	-478.8	-93.6	0
Non-Partnership loan facility:
Proceeds	92	65	90
Repayments	-74	-63	-96.8
Costs incurred in connection with financing arrangements	-14.3	-15.3	-36.6
Distributions to non-controlling interests	-341.4	-274.4	-211.5
Proceeds from sale of common units of the Partnership	412.7	524.7	514
Repurchase of common units under Partnership compensation plans	-4.8	0	0
Dividends to common shareholders	-113	-87.8	-62.2
Repurchase of common stock under TRC compensation plans	-2.6	-13.3	-9.5
Excess tax benefit from stock-based awards	1	1.6	1.3
Net cash used in financing activities	3.9	634	1,093
Net change in cash and cash equivalents	14.3	-9.6	-69.5
Cash and cash equivalents, beginning of period	66.7	76.3	145.8
Cash and cash equivalents, end of period	$81	$66.70	$76.30

Organization

Organization	12 Months Ended
	Dec. 31, 2014
Organization [Abstract]
Organization	Note 1 — Organization
	Targa Resources Corp. (“TRC”) is a Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations.

Basis_of_Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Basis of Presentation [Abstract]
Basis of Presentation	Note 2 — Basis of Presentation
	These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2014, 2013 and 2012.
	We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. Certain amounts in prior periods have been reclassified to conform to the current year presentation.
	One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership”). Because we control the general partner of the Partnership, under GAAP, we must reflect our ownership interests in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets is limited by the terms of the Partnership’s partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests and in our balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.
	As of December 31, 2014, our interests in the Partnership consist of the following:
		·	a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;
		·	all Incentive Distribution Rights (“IDRs”); and
		·	12,945,659 common units of the Partnership, representing a 10.9% limited partnership interest.
	The Partnership is 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 24 for an analysis of our and the Partnership’s operations by business segment.
	The Partnership does not have any employees. We provide operational, general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. We perform centralized corporate functions for the Partnership, 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 the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on the behalf of the Partnership. We charge the Partnership for all the direct costs of the employees assigned to its operations, as well as all general and administrative support costs other than (1) costs attributable to our status as a separate reporting company and (2) our costs of providing management and support services to certain unaffiliated spun-off entities. The Partnership generally reimburses us monthly for cost allocations to the extent that we have made a cash outlay.
	Revision of Previously Reported Revenues and Product Purchases
	During the third quarter of 2014, the Partnership 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.
	The Partnership concluded that these misclassifications were not material to any of the periods affected. However, the Partnership has 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 its 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		$	6,556.00		$	5,885.70
	Product Purchases			5,378.50			4,879.00
	Effect of Revisions:
	Revenues			(241.3	)		(206.7	)
	Product Purchases			(241.3	)		(206.7	)
	As Revised:
	Revenues			6,314.70			5,679.00
	Product Purchases			5,137.20			4,672.30

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
	The Partnership’s 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 the Partnership’s 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
	The Partnership employs 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. The Partnership has 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.
	The Partnership formally documents all relationships between hedging instruments and hedged items, as well as its 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, the Partnership assesses 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. The Partnership measures 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.
	The Partnership 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, the Partnership analyzes the fair values of the derivative contracts on a deal by deal basis and reports the related fair values on a gross basis.
	Property, Plant and Equipment
	Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of the property, plant and equipment sold to the Partnership 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.
	The 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 the Partnership’s 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 the Partnership has 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 account for income taxes using the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
	As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets.
	We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
	We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no valuation allowance has been established.
	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, which for the Partnership gives effect to the incentive distribution rights declared for each period. We account for the difference between the carrying amount of our investment in the Partnership and the underlying book value arising from issuance of common units by the Partnership, where we maintain control, as an equity transaction. If the Partnership issues common units at a price different than our carrying value per unit, we account for the excess or deficiency as an adjustment to paid-in capital.
	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.
	Share-Based Compensation
	We award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted stock units, stock options 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 Share
	We account for earnings per share (“EPS”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. 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 EPS.
	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, the Partnership 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 the Partnership’s portfolio of midstream assets and diversifies its business with the addition of fee-based crude oil gathering and natural gas gathering and processing. The Badlands financial results are included in the Partnership’s 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, the Partnership 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, the Partnership incurred $6.1 million of acquisition-related costs associated with the Badlands acquisition (included in Other expense in its Consolidated Statements of Operations).
	The following table shows the unaudited pro forma consolidated results of operations for the year ended 2012.
			2012
			(In millions except per share amounts)
	Revenues		$	5,909.90
	Net income			129.5
	Less: Net income attributable to noncontrolling interests			83.5
	Net income attributable to Targa Resources Corp.		$	46
	Net income per common share - Basic		$	1.12
	Net income per common share - Diluted		$	1.1
	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 Partnership’s debt offering and borrowings under the Partnership’s Senior Secured Revolving Credit Facility (the “TRP Revolver") used to fund a portion of the acquisition;
		·	adjust the attribution of net income to noncontrolling interests to give effect to the pro forma adjustments on the Partnership’s net income;
		·	include the income tax effect for us; 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 the Partnership announced two proposed merger transactions which would result in the Partnership’s 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, we would relinquish the APL general partner and IDR ownership interests and merge the APL general partner into the Partnership. Each of the Transactions is contingent on one another, and is expected to close concurrently on February 28, 2015, subject to the approval of our stock issuance in connection with the ATLS Merger by our 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:
		·	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 the Partnership’s 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 the Partnership’s common units will fluctuate in value until the closing date as a result of fluctuations in the market price of the Partnership’s common units.
	In connection with the APL Merger, we have agreed to reduce our 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 our common shares for each ATLS common unit. This equates to 10.35 million shares of our common stock and $522 million in cash payments. Additionally, we 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 our common shares will fluctuate in value until the closing date as a result of fluctuations in the market price of our common shares.
	Targa Pre-Closing Merger Financing Activities
	We have arranged committed financing of $1.1 billion to replace our 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, we announced the launch of a $430 million senior secured term loan maturing 7 years after closing and a $670 million revolving credit facility maturing 5 years after closing. These facilities are subject to the closing of the pending Atlas Mergers and market conditions.
	Partnership Pre-Closing Merger Financing Activities
	In January 2015, the Partnership 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 the Partnership at its 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 February 6, 2015
	$500 million 6⅝ due 2020		Less than majority
	$400 million 4¾ due 2021		98.30%
	$650 million 5⅞% due 2023		91.60%
	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, the Partnership is 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 Partnership’s previously announced tender offer for the APL Notes. The Change of Control Offer is scheduled to expire on March 3, 2015, unless extended by the Partnership. 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, the Partnership 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.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Inventories	Note 5 — Inventories
		31-Dec-14		31-Dec-13
	Partnership:
	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
		Targa Resources Partners LP			TRC Non-Partnership			Targa Resources Corp. Consolidated			Targa Resources Partners LP			TRC Non-Partnership			Targa Resources Corp. Consolidated			Estimated Useful Lives (In Years)
	Gathering systems	$	2,588.60		$	-		$	2,588.60		$	2,230.10		$	-		$	2,230.10		5 to 20
	Processing and fractionation facilities		1,884.10			6.6			1,890.70			1,598.00			6.6			1,604.60		5 to 25
	Terminaling and storage facilities		1,038.90			-			1,038.90			715.2			-			715.2		5 to 25
	Transportation assets		359			-			359			294.7			-			294.7		10 to 25
	Other property, plant and equipment		149.1			0.2			149.3			121.3			0.2			121.5		3 to 25
	Land		95.6			-			95.6			89.5			-			89.5		-
	Construction in progress		399			-			399			702.8			-			702.8		-
	Property, plant and equipment		6,514.30			6.8			6,521.10			5,751.60			6.8			5,758.40
	Accumulated depreciation		(1,689.7	)		(6.8	)		(1,696.5	)		(1,406.2	)		(2.3	)		(1,408.5	)
	Property, plant and equipment, net	$	4,824.60		$	-		$	4,824.60		$	4,345.40		$	4.5		$	4,349.90
	Intangible assets	$	681.8		$	-		$	681.8		$	681.8		$	-		$	681.8		20
	Accumulated amortization		(89.9	)		-			(89.9	)		(28.4	)		-			(28.4	)
	Intangible assets, net	$	591.9		$	-		$	591.9		$	653.4		$	-		$	653.4
	Intangible assets consist of customer contracts and customer relationships acquired in the Partnership’s 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
	The Partnership’s 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	$	50.9		$	45.3	$	42.3
	Change in cash flow estimate		2.1			1.6		(1.0	)
	Accretion expense		4.5			4		4
	Retirement of ARO		(0.2	)		-		-
	End of period	$	57.3		$	50.9	$	45.3

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 the Partnership’s 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 the Partnership’s 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
		Targa Resources Partners LP		TRC Non-Partnership			Targa Resources Corp. Consolidated		Targa Resources Partners LP		TRC Non-Partnership			Targa Resources Corp. Consolidated
	Commodities	$	416.7	$	-		$	416.7	$	529.7	$	(0.1	)	$	529.6
	Other goods and services		108.9		2.42			111.1		124.7		1.4			126.1
	Interest		37.3		-			37.3		35.9		0.1			36
	Compensation and benefits		1.3		44.8			46.1		1.3		38.9			40.2
	Income and other taxes		13.6		(1.9	)		11.7		10.9		(0.8	)		10.1
	Other		14.9		0.7			15.6		18.7		1.1			19.8
		$	592.7	$	45.8		$	638.5	$	721.2	$	40.6		$	761.8

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:
	Partnership
	Accounts receivable securitization facility, due December 2015 (1) (2)		$	182.8		$	-
	Long-term:
	Non-Partnership obligations:
	TRC Senior secured revolving credit facility, variable rate, due October 2017 (3)			102			84
	Obligations of the Partnership: (2)
	Senior secured revolving credit facility, variable rate, due October 2017 (4)			-			395
	Senior unsecured notes, 7⅞% fixed rate, due October 2018 (5)			-			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			2,885.40			2,989.30
	Total debt		$	3,068.20		$	2,989.30
	Irrevocable standby letters of credit:
	Letters of credit outstanding under TRC Senior secured credit facility (3)		$	-		$	-
	Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)			44.1			86.8
			$	44.1		$	86.8
	___________
	-1	The classification of the Partnership’s 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 the Partnership had the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. As of December 31, 2013, the Partnership 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 its Senior Secured Revolving Credit Facility. As of December 31, 2014, the Partnership intended to fund the Securitization Facility’s borrowings solely through further extensions of the termination date of the Securitization Facility, based on its 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	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
	-3	As of December 31, 2014, availability under TRC’s $150 million senior secured revolving credit facility was $48.0 million.
	-4	As of December 31, 2014, availability under the Partnership’s $1.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,155.9 million.
	-5	The outstanding balance of the 7⅞% Notes was redeemed in November 2014. See “The Partnership’s 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
	TRC Senior secured revolving credit facility		$	102		$	-			$	-			$	102			$	-			$	-			$	-
	TRP Revolver			-			-				-				-				-				-				-
	Partnership's Senior unsecured notes			2,808.60			-				-				-				-				800				2,008.60
	Partnership's Securitization Facility			182.8			182.8				-				-				-				-				-
	Total		$	3,093.40		$	182.8			$	-			$	102			$	-			$	800			$	2,008.60
	The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the year ended December 31, 2014:
		Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
	TRC senior secured revolving credit facility	2.90%		2.90%
	Partnership's senior secured revolving credit facility	1.9% - 4.5%		2.00%
	Partnership's accounts receivable securitization facility	0.90%		0.90%
	Compliance with Debt Covenants
	As of December 31, 2014, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
	TRC Revolving Credit Agreement
	In October 2012, we entered into a Credit Agreement that replaced our variable rate Senior Secured Revolving Credit Facility due July 2014 with a new variable rate Senior Secured Credit Facility due October 3, 2017 (the “TRC Revolver”). The TRC Revolver increases available commitments to $150.0 million from $75.0 million, allows us to request up to an additional $100.0 million in commitment increases and includes a $30.0 million swing line sub-facility. Outstanding letters of credit and related outstanding reimbursement obligations may not exceed $50.0 million in the aggregate.
	In 2012, we incurred a charge of $0.2 million related to a partial write-off of debt issue costs associated with the previous credit facility as a result of a change in syndicate members under the new TRC 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 TRC Revolver.
	The TRC Revolver bears interest, at our option, at either (a) a base rate equal to the highest of the prime rate of Deutsche Bank Trust Company Americas, the administrative agent, the federal funds rate plus 0.5% and the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 1.75% to 2.5% (dependent upon the Company’s consolidated leverage ratio), or (b) LIBOR plus an applicable margin ranging from 2.75% to 3.5% (dependent upon the Company’s consolidated leverage ratio).
	We are required to pay a commitment fee ranging from 0.375% to 0.5% (dependent upon the Company’s consolidated leverage ratio) on the daily average unused portion of the TRC Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable ranging from 2.75% to 3.5% (dependent upon the Company’s consolidated leverage ratio).
	The TRC Revolver is secured by substantially all of the Company’s assets. The TRC Revolver requires us to maintain a consolidated leverage ratio (the ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) of no more than 4.00 to 1.00. The TRC Revolver restricts our ability to make dividends to shareholders if, on a pro forma basis after giving effect to such dividend, (a) any default or event of default has occurred and is continuing or (b) our consolidated leverage ratio exceeds 4.00 to 1.00. In addition, the TRC Revolver includes 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.
	TRC Holdco Loan Facility
	In August 2007, we borrowed $450 million under the TRC Holdco loan facility (“Holdco debt”).
	The following subsidiary repurchases of Holdco debt have been recognized as extinguishments of debt:
		·	In 2012, using proceeds from our TRC Revolver, we paid $88.8 million to extinguish the remaining $89.3 million outstanding borrowings of Holdco debt, resulting in a pretax gain of $0.5 million. In addition, we wrote-off $0.3 million of associated unamortized deferred debt issue costs.
	The Partnership’s Revolving Credit Agreement
	In October 2012, the Partnership entered into a Second Amended and Restated Credit Agreement that amended and replaced its variable rate Senior Secured Credit Facility due July 2015 to provide the TRP Revolver 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, the Partnership 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
	The Partnership is required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on the Partnership’s 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 the Partnership’s ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
	The TRP Revolver is collateralized by a majority of the Partnership’s assets. Borrowings are guaranteed by the Partnership’s restricted subsidiaries.
	The TRP Revolver restricts the Partnership’s 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 the Partnership 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 the Partnership 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, the Partnership’s 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 the Partnership’s right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).
	The Partnership’s Senior Unsecured Notes
	In January 2012, the Partnership privately placed $400.0 million in aggregate principal amount of its 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 5¼% Notes were issued by the Partnership 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 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, the Partnership 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, the Partnership 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, the Partnership 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, the Partnership 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, the Partnership 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, the Partnership 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 the Partnership and the Partnership’s restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of the Partnership’s assets and the Partnership’s Securitization Facility, which is secured by accounts receivable pledged under the 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.
The Partnership’s senior unsecured notes and associated indenture agreements restrict the Partnership’s ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its 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 the Partnership and its subsidiaries will cease to be subject to such covenants.
The Partnership 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		106.88%
6⅜% Notes		1-Feb-15		106.38%
5¼% Notes		1-Nov-15		105.25%
4¼% Notes		15-May-16		104.25%
4⅛% Notes		15-Nov-19		104.13%
The Partnership 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	%					102.125	%		2018				101.75	%			2019				101.417	%		2017		101.031	%
					2018
2018			101.146	%					101.063	%		2019				100.875	%			2020				100.708	%		2018 and thereafter		100	%
					2019
2019 and thereafter			100	%	2020 and thereafter				100	%		2020 and thereafter				100	%		2021 and thereafter					100	%
The Partnership’s 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 the Partnership’s consolidated subsidiaries (Targa Liquids Marketing and Trade LLC (“TLMT”) and Targa Gas Marketing LLC (“TGM”)) sell or contribute receivables, without recourse, to another of its 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 the Partnership. Any excess receivables are eligible to satisfy the claims of creditors of TLMT, TGM or the Partnership. As of December 31, 2014, total funding under the Securitization Facility was $182.8 million.
The Partnership’s April 2013 Shelf
In April 2013, the Partnership filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provides the Partnership with the ability to offer and sell an unlimited  amount of debt and equity securities, subject to market conditions and the Partnership’s 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.
The Partnership’s July 2013 Shelf
In July 2013, the Partnership filed with the SEC a universal shelf registration statement that allows it 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:
Partnership 6⅜ Notes		$	-		$	6.4			$	-
Partnership 7⅞ Notes			9.9			-				-
Partnership 8¼ Notes			-			-				8.6
Partnership 11¼ Notes			-			4.1				-
Recognition of unamortized discount:
Partnership 11¼ Notes			-			2.2				-
Write-off of deferred debt issue costs:
Partnership 6⅜ Notes			-			1				-
Partnership 7⅞ Notes			2.5			-				-
Partnership 8¼ Notes			-			-				2.5
Partnership 11¼ Notes			-			1				-
TRC Holdco Notes			-			-				0.3
Partial write-off of deferred debt issue costs related to amendments:
TRP Revolver			-			-				1.7
TRC Revolver			-			-				0.2
Gain on acquisition of TRC Holdco Notes			-			-				(0.5	)
Loss on debt redemptions and amendments		$	12.4		$	14.7			$	12.8
Subsequent Events
We have 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, we announced the launch of a $430 million senior secured term loan maturing 7 years after closing and a $670 million revolving credit facility maturing 5 years after closing. These facilities are subject to the closing of the pending Atlas Mergers and market conditions.

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, the Partnership filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provides the Partnership with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and the Partnership’s 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, we purchased 1,300,000 common units with an aggregate value of $49.8 million. We contributed $3.5 million to maintain our 2% general partner interest. The Partnership 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. We contributed $8.0 million to maintain our 2% general partner interest. The Partnership 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, the Partnership filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows the Partnership 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, the Partnership entered into an Equity Distribution Agreement (the “2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which the Partnership may sell, at its option, up to an aggregate of $100.0 million of its common units through Citigroup, as sales agent, under the 2012 Shelf. During the year ended December 31, 2013, the Partnership issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. We contributed $2.0 million to maintain our 2% general partner interest.
	In March 2013, the Partnership 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 sales agents, pursuant to which the Partnership may sell, at its option, up to an aggregate of $200.0 million of the Partnership common units. During the year ended December 31, 2013, the Partnership issued 4,204,751 common units, receiving net proceeds of $197.5 million. We contributed $4.1 million to maintain our 2% general partner interest.
	In August 2013, the Partnership 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 its sales agents, pursuant to which the Partnership may sell, at its option, up to an aggregate of $400.0 million of the Partnership’s common units. During the year ended 2013, the Partnership issued 4,259,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million. We contributed $4.7 million to the Partnership to maintain our 2% general partner interest.
	In May 2014, the Partnership entered into an additional equity distribution agreement under the 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 its sales agents, pursuant to which the Partnership may sell, at its option, up to an aggregate of $400 million of the Partnership’s common units.
	During the year ended  2014, pursuant to the August 2013 EDA and the May 2014 EDA, the Partnership 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 its sales agent), which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. We contributed $8.4 million to maintain our 2% general partner interest, of which $1.0 million was settled in January 2015.
	Subsequent Event
	In January 2015, the Partnership issued 284,137 common units and received proceeds of $13.0 million, net of commissions and fees, pursuant to the May 2014 EDA. We contributed $0.3 million to maintain our 2% general partner interest.
	Distributions
	In accordance with the Partnership Agreement, the Partnership must distribute all of its 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 the Partnership for the years presented.
				Distributions
	Three Months Ended		Date Paid or to be Paid	Limited Partners		General Partner						Distributions to Targa Resources Corp.		Distributions per limited partner unit
				Common		Incentive			2%	Total
	(In millions, except per unit amounts)
	2014
	31-Dec-14		13-Feb-15	$	96.3	$	38.4	$	2.7	$	137.4	$	51.6	$	0.81
	30-Sep-14		14-Nov-14		92.3		36		2.6		130.9		48.9		0.7975
	30-Jun-14		14-Aug-14		89.5		33.7		2.5		125.7		46.3		0.78
	31-Mar-14		15-May-14		87.2		31.7		2.4		121.3		44		0.7625
	2013
	31-Dec-13		14-Feb-14	$	84	$	29.5	$	2.3	$	115.8	$	41.5	$	0.7475
	30-Sep-13		14-Nov-13		79.4		26.9		2.2		108.5		38.6		0.7325
	30-Jun-13		14-Aug-13		75.8		24.6		2		102.4		35.9		0.715
	31-Mar-13		15-May-13		71.7		22.1		1.9		95.7		33		0.6975
	2012
	31-Dec-12		14-Feb-13	$	69	$	20.1	$	1.8	$	90.9	$	30.7	$	0.68
	30-Sep-12		14-Nov-12		59.1		16.1		1.5		76.7		26.2		0.6625
	30-Jun-12		14-Aug-12		57.3		14.4		1.5		73.2		24.2		0.6425
	31-Mar-12		15-May-12		55.5		12.7		1.4		69.6		22.2		0.6225

Common_Stock_and_Related_Matte

Common Stock and Related Matters	12 Months Ended
	Dec. 31, 2014
Common Stock and Related Matters [Abstract]
Common Stock and Related Matters	Note 12 — Common Stock and Related Matters
	The following table details the dividends declared and/or paid by us for the years ended December 31, 2014, 2013 and 2012:
	Three Months Ended		Date Paid or To Be Paid	Total Dividend Declared		Amount of Dividend Paid		Accrued Dividends (1)		Dividend Declared per Share of Common Stock
	(In millions, except per share amounts)
	2014
	31-Dec-14		17-Feb-15	$	32.8	$	32.6	$	0.2	$	0.775
	30-Sep-14		17-Nov-14		31		30.8		0.2		0.7325
	30-Jun-14		15-Aug-14		29.2		29		0.2		0.69
	31-Mar-14		16-May-14		27.4		27.2		0.2		0.6475
	2013
	31-Dec-13		18-Feb-14		25.6		25.5		0.1		0.6075
	30-Sep-13		15-Nov-13		24.1		23.7		0.4		0.57
	30-Jun-13		15-Aug-13		22.5		22.1		0.4		0.5325
	31-Mar-13		16-May-13		21		20.6		0.4		0.495
	2012
	31-Dec-12		15-Feb-13	$	19.4	$	19	$	0.4	$	0.4575
	30-Sep-12		15-Nov-12		18		17.3		0.7		0.4225
	30-Jun-12		15-Aug-12		16.7		16.1		0.6		0.39375
	31-Mar-12		16-May-12		15.5		15		0.5		0.365
	________
	-1	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
	Dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.

Earnings_per_Common_Share

Earnings per Common Share	12 Months Ended
	Dec. 31, 2014
Earnings per Common Share [Abstract]
Earnings per Common Share	Note 13 — Earnings per Common Share
	Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using weighted average shares outstanding during the period, incorporated with the dilutive effect of restricted stock awards and stock options. The dilutive effect was determined through the application of the treasury method.
	The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:
		2014		2013		2012
	Net income	$	423	$	201.3	$	159.3
	Less: Net income attributable to noncontrolling interests		320.7		136.2		121.2
	Net income attributable to common shareholders	$	102.3	$	65.1	$	38.1
	Weighted average shares outstanding - basic		42		41.6		41
	Net income available per common share - basic	$	2.44	$	1.56	$	0.93
	Weighted average shares outstanding		42		41.6		41
	Dilutive effect of unvested stock awards		0.1		0.5		0.8
	Weighted average shares outstanding - diluted		42.1		42.1		41.8
	Net income available per common share - diluted	$	2.43	$	1.55	$	0.91

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 14 — Derivative Instruments and Hedging Activities
	The Partnership’s Commodity Hedges
	The primary purpose of the Partnership’s commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity prices associated with a portion of its expected (i) natural gas equity volumes in its Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in its Field Gathering and Processing segment and the LOU business unit in its 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. The Partnership has 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 the Partnership’s 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 the Partnership’s 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. The Partnership’s natural gas and NGL hedges are settled using published index prices for delivery at various locations, which closely approximate the Partnership’s actual natural gas and NGL delivery points.
	The Partnership hedges a portion of its 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 the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of its underlying condensate equity volumes. Hedge ineffectiveness was immaterial for all periods presented.
	At December 31, 2014, the notional volumes of the Partnership’s 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
	The Partnership also enters into derivative instruments to help manage other short-term commodity-related business risks. The Partnership has not designated these derivatives as hedges and records changes in fair value and cash settlements to revenues.
	The Partnership’s 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
	The Partnership’s payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing its senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders.
	The fair value of the Partnership’s 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 the Partnership’s 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:
	Derivatives in Cash Flow		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Hedging Relationships		2014			2013				2012
Commodity contracts		$	59.7			$	(5.8	)		$	76.8
		$	59.7			$	(5.8	)		$	76.8
		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				46
		$	(6.6	)		$	14.9			$	38.1
Our consolidated earnings are also affected by the Partnership’s 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 as Hedging Instruments		Location of Gain Recognized in Income on Derivatives		2014				2013				2012
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 before income taxes through the end of 2017 based on year-end valuations.
		31-Dec-14				31-Dec-13
Commodity hedges, before tax (1)		$	60.3			$	(3.7	)
Interest rate hedges, before tax			-				(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 15 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 15 — 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
	The Partnership’s derivative instruments consist of financially settled commodity swaps and option contracts and fixed-price commodity contracts with certain counterparties. The Partnership determines the fair value of its 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. The Partnership has consistently applied these valuation techniques in all periods presented and we believe the Partnership has obtained the most accurate information available for the types of derivative contracts the Partnership holds.
	The fair values of the Partnership’s 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 the Partnership expects to receive or pay in the future on its 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:
		•	Senior secured revolving credit facilities and the Partnership’s Securitization Facility are based on carrying value, which approximates fair value as their interest rates are 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			81			81			-			-		-
	TRC Senior secured revolving credit facility			102			102			-			102		-
	Partnership's Senior secured revolving credit facility			-			-			-			-		-
	Partnership's Senior unsecured notes			2,783.40			2,731.50			-			2,731.50		-
	Partnership's 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
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			66.7			66.7			-			-		-
	TRC Senior secured revolving credit facility			84			84			-			84		-
	Partnership's Senior secured revolving credit facility			395			395			-			395		-
	Partnership's Senior unsecured notes			2,230.60			2,253.50			-			2,253.50		-
	Partnership's accounts receivable securitization facility			279.7			279.7			-			279.7		-
	___________
	-1	The fair value of the derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14. 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 the Partnership’s 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, the Partnership had five natural gas swaps categorized as Level 3. The significant unobservable inputs used in the fair value measurements of the Partnership’s 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, the Partnership 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 Liability/ (Asset)			Long-term Debt			Contingent Liability
	Balance, December 31, 2011		$	-		$	87.5		$	-
	Issuances			-			-			15.3
	Settlements included in Revenue			(0.1	)		-			-
	Unrealized losses included in OCI			0.7			-			-
	Debt extinguishment			-			(87.5	)		-
	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, the Partnership 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 16 — Related Party Transactions
	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. The Partnership is subject to paying a deficiency fee in instances where the Partnership does not deliver its minimum volume requirements as outlined in the Partnership and fractionation agreements with GCF.
	Relationship with Targa Resources Partners LP
	We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on the behalf of the Partnership.
	The employees supporting the Partnership’s operations are employees of us. The Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the provision of various general and administrative services for the benefit of the Partnership. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Since October 1, 2010, after the final conveyance of assets by us to the Partnership, substantially all of our general and administrative costs have been and will continue to be allocated to the Partnership, other than (1) costs attributable to our status as a separate reporting company and (2) our costs of providing management and support services to certain unaffiliated spun-off entities.
	Relationship with Sajet Resources LLC
	Former holders of our pre-IPO common equity, including certain of our executive managers and directors, own a controlling interest in Sajet Resources LLC (“Sajet”), which was spun-off in December 2010 prior to the IPO. Sajet owns certain technology rights, real property and ownership interests in Allied CNG Ventures LLC. We provide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. During 2014, we were reimbursed $1.4 million for such services provided.
	Relationship with Tesla Resources LLC
	In September 2012, Tesla Resources LLC (“Tesla”) was spun-off from Sajet. Tesla has ownership interests in Floridian Natural Gas Storage Company LLC (“Floridian”). We provide general and administrative services to Tesla and Floridian and are reimbursed for these amounts at our actual cost. During 2014, we were reimbursed $0.2 million for such services provided.

Commitments_Leases

Commitments (Leases)	12 Months Ended
	Dec. 31, 2014
Commitments (Leases) [Abstract]
Commitments (Leases)	Note 17 — 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
	Non-Partnership obligations:
	Operating leases (1)		$	7.6	$	2.4	$	2.7	$	2.5	$	-	$	-
	Partnership obligations:
	Operating leases (2)			28.9		7.7		7.4		5.9		4.6		3.3
	Land site lease and right-of-way (3)			9.5		2		2		2		1.8		1.7
			$	46	$	12.1	$	12.1	$	10.4	$	6.4	$	5
	______________
	-1	Includes minimum payments on lease obligation for corporate office space.
	-2	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-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 the Partnership. 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
	Non-Partnership:
	Operating leases		$	3.3	$	2.8	$	2.1
	Partnership:
	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 18 – Contingencies
	Environmental
	The Partnership’s 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 19 – Significant Risks and Uncertainties
	Our primary business objective is to increase our available cash for dividends to our stockholders by assisting the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.
	Nature of the Partnership’s Operations in Midstream Energy Industry
	The Partnership operates in the midstream energy industry. Its business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. The Partnership’s 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.
	The Partnership’s 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 the Partnership’s  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 the Partnership receives 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 the Partnership’s control.
	In an effort to reduce the variability of our cash flows, the Partnership has entered into derivative financial instruments to hedge the commodity price associated with a significant portion of its expected natural gas equity volumes through 2017, NGL equity volumes through 2015 and condensate equity volumes through 2017. These derivative financial instruments included swaps and purchased puts (or floors). The Partnership hedges a higher percentage of its expected equity volumes in the earlier future periods. With swaps, the Partnership typically receives 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 the Partnership receives from its 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, the Partnership typically limits its use of swaps to hedge the prices of less than its expected natural gas and NGL equity volumes. The Partnership utilizes purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. The Partnership’s commodity hedges may expose it to the risk of financial loss in certain circumstances.
	The Partnership’s 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, the Partnership has entered into derivative financial instruments related to a portion of its 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 and the Partnership are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our and the Partnership’s credit facilities.
	Counterparty Risk – Credit and Concentration
	Derivative Counterparty Risk
	Where the Partnership is 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.
	The Partnership has master netting provisions in the International Swap Dealers Association agreements with all of its derivative counterparties. These netting provisions allow the Partnership to net settle asset and liability positions with the same counterparties, and would reduce its maximum loss due to counterparty credit risk by $4.4 million as of December 31, 2014. The range of losses attributable to the Partnership’s individual counterparties would be between $3.3 million and $27.5 million, depending on the counterparty in default.
	The 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 the Partnership to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the counterparties decline, the 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, the Partnership may sustain a loss and its 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	$	1.1		$	0.9		$	2.4
	Additions		-			0.2			-
	Deductions		(1.1	)		-			(1.5	)
	Balance at end of year	$	-		$	1.1		$	0.9
	Significant Commercial Relationship
		2014			2013			2012
	% of consolidated revenues
	Chevron Phillips Chemical Company LLC		4	%		8	%		10	%
	The transactions in the above table were primarily associated with the Marketing and Distribution segment.
	Casualty or Other Risks
	We maintain coverage in various insurance programs, which provides us and the Partnership with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to the Partnership by us through the Partnership Agreement described in Note 16.
	Management believes that we have 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, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
	If we or the Partnership 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 the Partnership, or which causes us or the Partnership to make significant expenditures not covered by insurance, could reduce our or the Partnership’s 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 20 – 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 the Partnership’s investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Income Taxes	Note 21—Income Taxes
	Our provisions for income taxes for the periods indicated are as follows:
			2014			2013			2012
	Current expense		$	72.4		$	42.8		$	27.9
	Deferred expense (benefit)			(4.4	)		5.4			9
			$	68		$	48.2		$	36.9
	Our deferred income tax assets and liabilities at December 31, 2014 and 2013 consist of differences related to the timing of recognition of certain types of costs as follows:
			2014			2013
	Deferred tax assets:
	Deferred tax assets before valuation allowance		$	3.5		$	3.5
	Valuation allowance			(3.5	)		(3.5	)
			$	-		$	-
	Deferred tax liabilities:
	Investments (1)		$	(115.8	)	$	(115.2	)
	Debt related deferreds			(13.4	)		(17.2	)
	Other			(9.5	)		(7.1	)
				(138.7	)		(139.5	)
			$	(138.7	)	$	(139.5	)
	Net deferred tax liability:
	Federal		$	(115.5	)	$	(121.0	)
	Foreign			0.6			0.6
	State			(23.8	)		(19.1	)
			$	(138.7	)	$	(139.5	)
	Balance sheet classification of deferred tax assets (liabilities):
	Long-term asset		$	-		$	(3.5	)
	Current liability			(0.5	)		(0.5	)
	Long-term liability			(138.2	)		(135.5	)
			$	(138.7	)	$	(139.5	)
	_________
	-1	Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our investments.
	As a result of dropdown transactions in 2010 and 2009, differences related to the date of income recognition for book and tax occurred, resulting in deferred tax assets. The reversal of these differences will not be recognized until we sell the units of the Partnership. Therefore, a valuation allowance of $3.5 million has been placed against these deferred assets.
	Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated:
	Income tax reconciliation:		2014			2013			2012
	Income before income taxes		$	491		$	249.5		$	196.2
	Less: Net income attributable to noncontrolling interest			(320.7	)		(136.2	)		(121.2	)
	Less: Income taxes included in noncontrolling interest			(4.2	)		(2.5	)		(3.5	)
	Income attributable to TRC before income taxes			166.1			110.8			71.5
	Federal statutory income tax rate			35	%		35	%		35	%
	Provision for federal income taxes			58.1			38.8			25
	State income taxes, net of federal tax benefit			6.7			4.4			6.8
	Amortization of deferred charge on 2010 transactions			4.7			4.7			4.7
	Other, net			(1.5	)		0.3			0.4
	Income tax provision		$	68		$	48.2		$	36.9
	We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 22 - Supplemental Cash Flow Information
			2014		2013			2012
	Cash:
	Interest paid, net of capitalized interest (1)		$	133.8	$	121.7		$	95.6
	Income taxes paid, net of refunds			73.4		34.1			30.5
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			14.8		30.4			3
	Accrued dividends on unvested equity awards			0.6		1.6			2.7
	Badlands contingent consideration recorded at acquisition date			-		-			15.3
	Change in capital accruals			19		(0.4	)		(34.3	)
	Transfers from materials and supplies to property, plant and equipment			4.6		20.5			-
	Change in ARO estimate			2.1		1.6			(1.0	)
	___________
	-1	Interest capitalized on expansion projects was $16.1 million, $28.0 million and $13.6 million for the years ended December 31, 2014, 2013 and 2012.

Stock_and_Other_Compensation_P

Stock and Other Compensation Plans	12 Months Ended
	Dec. 31, 2014
Stock and Other Compensation Plans [Abstract]
Stock and Other Compensation Plans	Note 23 – Stock and Other 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
	2010 TRC Stock Incentive Plan
	Restricted Stock Awards
	Restricted Stock Units Awards
	TRC Director Grants
	Targa 401(k) Plan
	TRC Long-Term Incentive Plan
	Cash-settled Performance Units
	The Partnership Equity-Settled Performance Units
	The Partnership started issuing equity-settled performance units in 2011. The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2014, 2013, and 2012:
			Number				Weighted Average Grant-Date Fair Value
			of units
	Outstanding at December 31, 2011			135,870			$	33.94
	Granted			171,750				41.94
	Outstanding at December 31, 2012			307,620				38.4
	Granted			244,578				46.54
	Outstanding at December 31, 2013			552,198				42.01
	Granted			168,495				57.19
	Vested			(137,170	)			34.02
	Forfeited			(6,120	)			49.39
	Outstanding at December 31, 2014			577,403				48.26
	Subsequent Event - On January 21, 2015, the Committee made awards to the executive management for the 2015 compensation cycle of 103,760 equity-settled performance units under our LTIP that will vest in June 2018.
	Partnership Director Grants
	Starting in 2011, the common units granted to the Partnership’s non-management directors were vested immediately at the grant date.
	The following table summarizes activity of the common unit-based awards granted to the Partnership’s Directors for the years ended December 31, 2014, 2013 and 2012 (in units and dollars):
			Number of units				Weighted Average 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 LTIP -- 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
	In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC 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:
							Weighted-average
			Number of shares				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 Events
On January 2015, the compensation committee (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, we 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.
On January 15, 2015, the Committee awarded 5,862 shares of our common stock to our outside directors. The awards vested at grant date.
Long-Term Incentive Plans
Performance Units
In 2007 both we and the Partnership adopted Long-Term Incentive Plans (“LTIP”) for employees, consultants, directors and non-employee directors of us and our affiliates who perform services for us or our affiliates. The performance units granted under these plans are linked to the performance of the Partnership’s 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 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. We have used a Monte Carlo simulation model to estimate accruals throughout the vesting period. In 2012, we 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.
The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicated:
		2014				2013			2012
2010 TRC Stock Incentive Plan - Director Grants		$	0.5			$	0.5		$	0.4
Partnership Equity-Settled Performance Units			8.8				5.5			3.1
Partnership Director Grants			0.4				0.5			0.5
Allocated to the Partnership
2010 TRC Stock Incentive Plan - Restricted Stock			2.2				6.3			13.7
2010 TRC Stock Incentive Plan - Restricted Stock Unit			2.5				0.4			-
TRC LTIP - Cash-Settled Performance Units			11				21.9			14.2
The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various compensation plans as of December 31, 2014:
					Weighted Average
	December 31,				Remaining
	2014				Vesting Period
	(In millions)				(In years)
Partnership 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
TRC Cash-Settled Performance Units		$	14.7			$	25.2		$	22.2
Partnership Equity - Settled Performance Units			10				-			-
Accrued DERs settled for Equity - Settled Performance Units			1.6				-			-
Partnership Director Grants			0.4				0.7			1
2010 TRC Stock Incentive Plan - Restricted Stock (1)			7.1				42.2			40.3
2010 TRC Stock Incentive Plan - Director Grants			0.5				0.5			0.4
Accrued dividends settled			0.5				2.4			2
________
-1	We recognized $1.0 million, $1.6 million and $1.3 million in tax benefits associated with the vesting of the restricted stock in 2014, 2013 and 2012.
401(k) Plan
We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute 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. We 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 Information [Abstract]
Segment Information	Note 24 — Segment Information
	The Partnership reports its 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 its hedging activities on reported profits are reported in Other.
	The Partnership’s 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.
	The Partnership’s Logistics and Marketing division is also referred to as its Downstream Business. The Partnership’s 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 the Partnership’s other operations, including services to LPG exporters, as well as transporting natural gas and NGLs.
	The Partnership’s 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 the Partnership’s Gathering and Processing segments and are predominantly located in Mont Belvieu, and Galena Park, Texas and Lake Charles, Louisiana.
	The Partnership’s 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 the Partnership’s 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 the Partnership from its 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 the Partnership’s commodity hedging activities included in operating margin. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.
	Segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities.
			Year Ended December 31, 2014
			Field			Coastal
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	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	)	$	-		$	(0.1	)	$	1,136.50
	Other financial information:
	Total assets (1)		$	3,409.00		$	367.2		$	1,717.30		$	708.5	$	60.2		$	115		$	76.3		$	6,453.50
	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
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	Revenues
	Sales of commodities		$	188.8		$	305		$	140.5		$	5,072.40	$	21.4		$	0.1		$	(0.2	)	$	5,728.00
	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			-			(0.2	)		6,314.70
	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	)	$	(0.2	)	$	6,314.70
	Operating margin		$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	(0.3	)	$	801.2
	Other financial information:
	Total assets		$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	77.2		$	6,048.60
	Capital expenditures		$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	-		$	1,034.50
			Year Ended December 31, 2012
			Field			Coastal
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	Revenues
	Sales of commodities		$	172.7		$	240.6		$	184.4		$	4,680.20	$	41.1		$	-		$	2.1		$	5,321.10
	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	)		2.1			5,679.00
	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	)	$	2.1		$	5,679.00
	Operating margin		$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	1.9		$	693.6
	Other financial information:
	Total assets		$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	79.3		$	5,105.00
	Capital expenditures		$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	0.3		$	617
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	)		21.5			44.3
			7,595.20			5,728.00			5,321.10
Fees from midstream services
Fractionating and treating			208.9			133.9			110.1
Storage, terminaling, transportation and export			548			280.3			162.5
Gathering and processing			196.9			114.1			45
Other			67.5			58.4			40.3
			1,021.30			586.7			357.9
Total revenues		$	8,616.50		$	6,314.70			5,679.00
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		$	1,136.50		$	801.2		$	693.6
Depreciation and amortization expense			(351.0	)		(271.9	)		(197.6	)
General and administrative expense			(148.0	)		(151.5	)		(139.8	)
Interest expense, net			(147.1	)		(134.1	)		(120.8	)
Other, net			0.6			5.8			(39.2	)
Income tax expense			(68.0	)		(48.2	)		(36.9	)
Net income		$	423		$	201.3		$	159.3

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 25 — 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
		Quarter		Quarter		Quarter		Quarter		Total
		(In millions, except per share 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		158.4		150.3		168.7		163.1		640.5
	Net income		106.9		103.2		120.4		92.5		423
	Net income attributable to Targa / common shareholders		19.6		26.4		30.7		25.6		102.3
	Net income per common share - basic	$	0.47	$	0.63	$	0.73	$	0.61	$	2.44
	Net income per common share - diluted	$	0.47	$	0.63	$	0.73	$	0.61	$	2.43
	2013
	Revenues	$	1,373.80	$	1,370.50	$	1,466.00	$	2,104.40	$	6,314.70
	Gross margin		260.3		265.2		297		355		1,177.50
	Operating income		73.9		60.9		88.5		144.9		368.2
	Net income		33.8		22.5		49.4		95.6		201.3
	Net income attributable to Targa / common shareholders		13.4		15		16.3		20.4		65.1
	Net income per common share - basic	$	0.32	$	0.36	$	0.39	$	0.49	$	1.56
	Net income per common share - diluted	$	0.32	$	0.36	$	0.39	$	0.48	$	1.55

Condensed_Parent_Only_Financia

Condensed Parent Only Financial Statements	12 Months Ended
	Dec. 31, 2014
Condensed Parent Only Financial Statements [Abstract]
Condensed Parent Only Financial Statements	Note 26— Condensed Parent Only Financial Statements
	The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X for Targa Resources Corp.
	In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balance sheets. The income (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries.
	A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual Report.
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED BALANCE SHEETS
		December 31,
		2014			2013
		(In millions)
	ASSETS
	Investment in consolidated subsidiaries	$	243.8		$	208.4
	Deferred income taxes		27.9			23.9
	Long-term debt issue costs		1			1.4
	Total assets	$	272.7		$	233.7
	LIABILITIES AND STOCKHOLDERS' EQUITY
	Accrued current liabilities	$	0.6		$	0.6
	Long-term debt		102			84
	Other long-term liabilities		0.3			0.3
	Commitments and contingencies
	Targa Resources Corp. stockholders' equity		169.8			148.8
	Total liabilities and stockholders' equity	$	272.7		$	233.7
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED STATEMENTS OF OPERATIONS
		Year Ended December 31,
		2014			2013			2012
		(In millions, except per share amounts)
	Equity in net income (loss) of consolidated subsidiaries	$	109.8		$	72.6		$	45.4
	General and administrative expenses		(8.3	)		(8.4	)		(8.2	)
	Income (loss) from operations		101.5			64.2			37.2
	Other income (expense):
	Gain on debt extinguishment		-			-			0.2
	Interest expense		(3.2	)		(3.2	)		(3.2	)
	Income (loss) before income taxes		98.3			61			34.2
	Deferred income tax (expense) benefit		4			4.1			3.9
	Net income (loss) available to common shareholders	$	102.3		$	65.1		$	38.1
	Net income (loss) available per common share - basic	$	2.44		$	1.56		$	0.93
	Net income (loss) available per common share - diluted	$	2.43		$	1.55		$	0.91
	Weighted average shares outstanding - basic		42			41.6			41
	Weighted average shares outstanding - diluted		42.1			42.1			41.8
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED STATEMENTS OF CASH FLOWS
		Year Ended December 31,
		2014			2013			2012
		(In millions)
	Net cash provided by operating activities	$	(1.3	)	$	(4.1	)	$	0.8
	Investing activities:
	Distribution and return of advances from consolidated subsidiaries		97.3			101.6			78.6
	Net cash provided by investing activities		97.3			101.6			78.6
	Financing activities:
	Long-term debt borrowings		92			65			90
	Long-term debt repayments		(74.0	)		(63.0	)		(96.8	)
	Costs incurred in connection with financing arrangements		-			-			(1.0	)
	Repurchase of common stock		-			(13.3	)		(9.5	)
	Dividends to common and common equivalent shareholders		(113.0	)		(87.8	)		(62.2	)
	Excess tax benefit from stock-based awards		(1.0	)		1.6			1.3
	Distribution to owners		-			-			(1.2	)
	Net cash used in financing activities		(96.0	)		(97.5	)		(79.4	)
	Net increase (decrease) in cash and cash equivalents		-			-			-
	Cash and cash equivalents - beginning of year		-			-			-
	Cash and cash equivalents - end of year	$	-		$	-		$	-

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
	The Partnership’s 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 the Partnership’s 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
	The Partnership employs 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. The Partnership has 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.
	The Partnership formally documents all relationships between hedging instruments and hedged items, as well as its 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, the Partnership assesses 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. The Partnership measures 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.
	The Partnership 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, the Partnership analyzes the fair values of the derivative contracts on a deal by deal basis and reports the related fair values 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 the property, plant and equipment sold to the Partnership 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.
	The 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 the Partnership’s 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 the Partnership has 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 account for income taxes using the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
	As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets.
	We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
	We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no valuation allowance has been established.
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, which for the Partnership gives effect to the incentive distribution rights declared for each period. We account for the difference between the carrying amount of our investment in the Partnership and the underlying book value arising from issuance of common units by the Partnership, where we maintain control, as an equity transaction. If the Partnership issues common units at a price different than our carrying value per unit, we account for the excess or deficiency as an adjustment to paid-in capital.
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.
Share-Based Compensation	Share-Based Compensation
	We award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted stock units, stock options 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 Share	Earnings per Share
	We account for earnings per share (“EPS”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. 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 EPS.
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	The Partnership concluded that these misclassifications were not material to any of the periods affected. However, the Partnership has 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 its 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	$	6,556.00		$	5,885.70
	Product Purchases		5,378.50			4,879.00
	Effect of Revisions:
	Revenues		(241.3	)		(206.7	)
	Product Purchases		(241.3	)		(206.7	)
	As Revised:
	Revenues		6,314.70			5,679.00
	Product Purchases		5,137.20			4,672.30

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.
		2012
		(In millions except per share amounts)
	Revenues	$	5,909.90
	Net income		129.5
	Less: Net income attributable to noncontrolling interests		83.5
	Net income attributable to Targa Resources Corp.	$	46
	Net income per common share - Basic	$	1.12
	Net income per common share - Diluted	$	1.1
Schedule of Outstanding APL Senior Notes	The outstanding APL Senior Notes consist of:
	APL Senior Notes	Amount tendered as of February 6, 2015
	$500 million 6⅝ due 2020	Less than majority
	$400 million 4¾ due 2021	98.30%
	$650 million 5⅞% due 2023	91.60%

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Components of Inventories		31-Dec-14		31-Dec-13
	Partnership:
	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
		Targa Resources Partners LP			TRC Non-Partnership			Targa Resources Corp. Consolidated			Targa Resources Partners LP			TRC Non-Partnership			Targa Resources Corp. Consolidated			Estimated Useful Lives (In Years)
	Gathering systems	$	2,588.60		$	-		$	2,588.60		$	2,230.10		$	-		$	2,230.10		5 to 20
	Processing and fractionation facilities		1,884.10			6.6			1,890.70			1,598.00			6.6			1,604.60		5 to 25
	Terminaling and storage facilities		1,038.90			-			1,038.90			715.2			-			715.2		5 to 25
	Transportation assets		359			-			359			294.7			-			294.7		10 to 25
	Other property, plant and equipment		149.1			0.2			149.3			121.3			0.2			121.5		3 to 25
	Land		95.6			-			95.6			89.5			-			89.5		-
	Construction in progress		399			-			399			702.8			-			702.8		-
	Property, plant and equipment		6,514.30			6.8			6,521.10			5,751.60			6.8			5,758.40
	Accumulated depreciation		(1,689.7	)		(6.8	)		(1,696.5	)		(1,406.2	)		(2.3	)		(1,408.5	)
	Property, plant and equipment, net	$	4,824.60		$	-		$	4,824.60		$	4,345.40		$	4.5		$	4,349.90
	Intangible assets	$	681.8		$	-		$	681.8		$	681.8		$	-		$	681.8		20
	Accumulated amortization		(89.9	)		-			(89.9	)		(28.4	)		-			(28.4	)
	Intangible assets, net	$	591.9		$	-		$	591.9		$	653.4		$	-		$	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 Partnership’s 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	$	50.9		$	45.3	$	42.3
	Change in cash flow estimate		2.1			1.6		(1.0	)
	Accretion expense		4.5			4		4
	Retirement of ARO		(0.2	)		-		-
	End of period	$	57.3		$	50.9	$	45.3

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 the Partnership’s 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 the Partnership’s 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
		Targa Resources Partners LP		TRC Non-Partnership			Targa Resources Corp. Consolidated		Targa Resources Partners LP		TRC Non-Partnership			Targa Resources Corp. Consolidated
	Commodities	$	416.7	$	-		$	416.7	$	529.7	$	(0.1	)	$	529.6
	Other goods and services		108.9		2.42			111.1		124.7		1.4			126.1
	Interest		37.3		-			37.3		35.9		0.1			36
	Compensation and benefits		1.3		44.8			46.1		1.3		38.9			40.2
	Income and other taxes		13.6		(1.9	)		11.7		10.9		(0.8	)		10.1
	Other		14.9		0.7			15.6		18.7		1.1			19.8
		$	592.7	$	45.8		$	638.5	$	721.2	$	40.6		$	761.8

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:
	Partnership
	Accounts receivable securitization facility, due December 2015 (1) (2)		$	182.8		$	-
	Long-term:
	Non-Partnership obligations:
	TRC Senior secured revolving credit facility, variable rate, due October 2017 (3)			102			84
	Obligations of the Partnership: (2)
	Senior secured revolving credit facility, variable rate, due October 2017 (4)			-			395
	Senior unsecured notes, 7⅞% fixed rate, due October 2018 (5)			-			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			2,885.40			2,989.30
	Total debt		$	3,068.20		$	2,989.30
	Irrevocable standby letters of credit:
	Letters of credit outstanding under TRC Senior secured credit facility (3)		$	-		$	-
	Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)			44.1			86.8
			$	44.1		$	86.8
	___________
	-1	The classification of the Partnership’s 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 the Partnership had the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. As of December 31, 2013, the Partnership 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 its Senior Secured Revolving Credit Facility. As of December 31, 2014, the Partnership intended to fund the Securitization Facility’s borrowings solely through further extensions of the termination date of the Securitization Facility, based on its 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	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
	-3	As of December 31, 2014, availability under TRC’s $150 million senior secured revolving credit facility was $48.0 million.
	-4	As of December 31, 2014, availability under the Partnership’s $1.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,155.9 million.
	-5	The outstanding balance of the 7⅞% Notes was redeemed in November 2014. See “The Partnership’s 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
	TRC Senior secured revolving credit facility		$	102		$	-			$	-			$	102			$	-			$	-			$	-
	TRP Revolver			-			-				-				-				-				-				-
	Partnership's Senior unsecured notes			2,808.60			-				-				-				-				800				2,008.60
	Partnership's Securitization Facility			182.8			182.8				-				-				-				-				-
	Total		$	3,093.40		$	182.8			$	-			$	102			$	-			$	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 variable-rate debt obligations during the year ended December 31, 2014:
		Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
	TRC senior secured revolving credit facility	2.90%		2.90%
	Partnership's senior secured revolving credit facility	1.9% - 4.5%		2.00%
	Partnership's accounts receivable securitization facility	0.90%		0.90%
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	The Partnership 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		106.88%
	6⅜% Notes		1-Feb-15		106.38%
	5¼% Notes		1-Nov-15		105.25%
	4¼% Notes		15-May-16		104.25%
	4⅛% Notes		15-Nov-19		104.13%
	The Partnership 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	%					102.125	%		2018				101.75	%			2019				101.417	%		2017		101.031	%
						2018
	2018			101.146	%					101.063	%		2019				100.875	%			2020				100.708	%		2018 and thereafter		100	%
						2019
	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:
	Partnership 6⅜ Notes		$	-		$	6.4			$	-
	Partnership 7⅞ Notes			9.9			-				-
	Partnership 8¼ Notes			-			-				8.6
	Partnership 11¼ Notes			-			4.1				-
	Recognition of unamortized discount:
	Partnership 11¼ Notes			-			2.2				-
	Write-off of deferred debt issue costs:
	Partnership 6⅜ Notes			-			1				-
	Partnership 7⅞ Notes			2.5			-				-
	Partnership 8¼ Notes			-			-				2.5
	Partnership 11¼ Notes			-			1				-
	TRC Holdco Notes			-			-				0.3
	Partial write-off of deferred debt issue costs related to amendments:
	TRP Revolver			-			-				1.7
	TRC Revolver			-			-				0.2
	Gain on acquisition of TRC Holdco Notes			-			-				(0.5	)
	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 the Partnership for the years presented.
			Distributions
	Three Months Ended	Date Paid or to be Paid	Limited Partners		General Partner						Distributions to Targa Resources Corp.		Distributions per limited partner unit
			Common		Incentive			2%	Total
	(In millions, except per unit amounts)
	2014
	31-Dec-14	13-Feb-15	$	96.3	$	38.4	$	2.7	$	137.4	$	51.6	$	0.81
	30-Sep-14	14-Nov-14		92.3		36		2.6		130.9		48.9		0.7975
	30-Jun-14	14-Aug-14		89.5		33.7		2.5		125.7		46.3		0.78
	31-Mar-14	15-May-14		87.2		31.7		2.4		121.3		44		0.7625
	2013
	31-Dec-13	14-Feb-14	$	84	$	29.5	$	2.3	$	115.8	$	41.5	$	0.7475
	30-Sep-13	14-Nov-13		79.4		26.9		2.2		108.5		38.6		0.7325
	30-Jun-13	14-Aug-13		75.8		24.6		2		102.4		35.9		0.715
	31-Mar-13	15-May-13		71.7		22.1		1.9		95.7		33		0.6975
	2012
	31-Dec-12	14-Feb-13	$	69	$	20.1	$	1.8	$	90.9	$	30.7	$	0.68
	30-Sep-12	14-Nov-12		59.1		16.1		1.5		76.7		26.2		0.6625
	30-Jun-12	14-Aug-12		57.3		14.4		1.5		73.2		24.2		0.6425
	31-Mar-12	15-May-12		55.5		12.7		1.4		69.6		22.2		0.6225

Common_Stock_and_Related_Matte1

Common Stock and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Common Stock and Related Matters [Abstract]
Dividends Declared and/or Paid	The following table details the dividends declared and/or paid by us for the years ended December 31, 2014, 2013 and 2012:
	Three Months Ended		Date Paid or To Be Paid	Total Dividend Declared		Amount of Dividend Paid		Accrued Dividends (1)		Dividend Declared per Share of Common Stock
	(In millions, except per share amounts)
	2014
	31-Dec-14		17-Feb-15	$	32.8	$	32.6	$	0.2	$	0.775
	30-Sep-14		17-Nov-14		31		30.8		0.2		0.7325
	30-Jun-14		15-Aug-14		29.2		29		0.2		0.69
	31-Mar-14		16-May-14		27.4		27.2		0.2		0.6475
	2013
	31-Dec-13		18-Feb-14		25.6		25.5		0.1		0.6075
	30-Sep-13		15-Nov-13		24.1		23.7		0.4		0.57
	30-Jun-13		15-Aug-13		22.5		22.1		0.4		0.5325
	31-Mar-13		16-May-13		21		20.6		0.4		0.495
	2012
	31-Dec-12		15-Feb-13	$	19.4	$	19	$	0.4	$	0.4575
	30-Sep-12		15-Nov-12		18		17.3		0.7		0.4225
	30-Jun-12		15-Aug-12		16.7		16.1		0.6		0.39375
	31-Mar-12		16-May-12		15.5		15		0.5		0.365
	________
	-1	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Earnings_per_Common_Share_Tabl

Earnings per Common Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings per Common Share [Abstract]
Reconciliation of Net Income and Weighted Average Shares Outstanding Used in Computing Basic and Diluted Net Income Per Common Share	The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:
		2014		2013		2012
	Net income	$	423	$	201.3	$	159.3
	Less: Net income attributable to noncontrolling interests		320.7		136.2		121.2
	Net income attributable to common shareholders	$	102.3	$	65.1	$	38.1
	Weighted average shares outstanding - basic		42		41.6		41
	Net income available per common share - basic	$	2.44	$	1.56	$	0.93
	Weighted average shares outstanding		42		41.6		41
	Dilutive effect of unvested stock awards		0.1		0.5		0.8
	Weighted average shares outstanding - diluted		42.1		42.1		41.8
	Net income available per common share - diluted	$	2.43	$	1.55	$	0.91

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 Partnership's Commodity Hedges	At December 31, 2014, the notional volumes of the Partnership’s 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:
	Derivatives in Cash Flow		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Hedging Relationships		2014			2013				2012
	Commodity contracts		$	59.7			$	(5.8	)		$	76.8
			$	59.7			$	(5.8	)		$	76.8
			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				46
			$	(6.6	)		$	14.9			$	38.1
Gain (Loss) Recognized in Income on Derivatives	Our consolidated earnings are also affected by the Partnership’s 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 as Hedging Instruments		Location of Gain Recognized in Income on Derivatives		2014				2013				2012
	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 before income taxes through the end of 2017 based on year-end valuations.
			31-Dec-14				31-Dec-13
	Commodity hedges, before tax (1)		$	60.3			$	(3.7	)
	Interest rate hedges, before tax			-				(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			81			81			-			-		-
	TRC Senior secured revolving credit facility			102			102			-			102		-
	Partnership's Senior secured revolving credit facility			-			-			-			-		-
	Partnership's Senior unsecured notes			2,783.40			2,731.50			-			2,731.50		-
	Partnership's 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
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			66.7			66.7			-			-		-
	TRC Senior secured revolving credit facility			84			84			-			84		-
	Partnership's Senior secured revolving credit facility			395			395			-			395		-
	Partnership's Senior unsecured notes			2,230.60			2,253.50			-			2,253.50		-
	Partnership's accounts receivable securitization facility			279.7			279.7			-			279.7		-
	___________
	-1	The fair value of the derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14. 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 Liability/ (Asset)			Long-term Debt			Contingent Liability
	Balance, December 31, 2011		$	-		$	87.5		$	-
	Issuances			-			-			15.3
	Settlements included in Revenue			(0.1	)		-			-
	Unrealized losses included in OCI			0.7			-			-
	Debt extinguishment			-			(87.5	)		-
	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	)	$	-		$	-

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
	Non-Partnership obligations:
	Operating leases (1)		$	7.6	$	2.4	$	2.7	$	2.5	$	-	$	-
	Partnership obligations:
	Operating leases (2)			28.9		7.7		7.4		5.9		4.6		3.3
	Land site lease and right-of-way (3)			9.5		2		2		2		1.8		1.7
			$	46	$	12.1	$	12.1	$	10.4	$	6.4	$	5
	______________
	-1	Includes minimum payments on lease obligation for corporate office space.
	-2	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-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 the Partnership. These agreements expire at various dates, with varying terms, some of which are perpetual.
Total Expenses Incurred under Lease Obligations	Total expenses incurred under the above lease obligations were:
			2014		2013		2012
	Non-Partnership:
	Operating leases		$	3.3	$	2.8	$	2.1
	Partnership:
	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	$	1.1		$	0.9		$	2.4
	Additions		-			0.2			-
	Deductions		(1.1	)		-			(1.5	)
	Balance at end of year	$	-		$	1.1		$	0.9
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 the Partnership’s investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Provisions for Income Taxes	Our provisions for income taxes for the periods indicated are as follows:
			2014			2013			2012
	Current expense		$	72.4		$	42.8		$	27.9
	Deferred expense (benefit)			(4.4	)		5.4			9
			$	68		$	48.2		$	36.9
Deferred Tax Assets and Liabilities	Our deferred income tax assets and liabilities at December 31, 2014 and 2013 consist of differences related to the timing of recognition of certain types of costs as follows:
			2014			2013
	Deferred tax assets:
	Deferred tax assets before valuation allowance		$	3.5		$	3.5
	Valuation allowance			(3.5	)		(3.5	)
			$	-		$	-
	Deferred tax liabilities:
	Investments (1)		$	(115.8	)	$	(115.2	)
	Debt related deferreds			(13.4	)		(17.2	)
	Other			(9.5	)		(7.1	)
				(138.7	)		(139.5	)
			$	(138.7	)	$	(139.5	)
	Net deferred tax liability:
	Federal		$	(115.5	)	$	(121.0	)
	Foreign			0.6			0.6
	State			(23.8	)		(19.1	)
			$	(138.7	)	$	(139.5	)
	Balance sheet classification of deferred tax assets (liabilities):
	Long-term asset		$	-		$	(3.5	)
	Current liability			(0.5	)		(0.5	)
	Long-term liability			(138.2	)		(135.5	)
			$	(138.7	)	$	(139.5	)
	_________
	-1	Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our investments.
Reconciliation of Income Tax Provision (Benefit)	Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated:
	Income tax reconciliation:		2014			2013			2012
	Income before income taxes		$	491		$	249.5		$	196.2
	Less: Net income attributable to noncontrolling interest			(320.7	)		(136.2	)		(121.2	)
	Less: Income taxes included in noncontrolling interest			(4.2	)		(2.5	)		(3.5	)
	Income attributable to TRC before income taxes			166.1			110.8			71.5
	Federal statutory income tax rate			35	%		35	%		35	%
	Provision for federal income taxes			58.1			38.8			25
	State income taxes, net of federal tax benefit			6.7			4.4			6.8
	Amortization of deferred charge on 2010 transactions			4.7			4.7			4.7
	Other, net			(1.5	)		0.3			0.4
	Income tax provision		$	68		$	48.2		$	36.9

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)		$	133.8	$	121.7		$	95.6
	Income taxes paid, net of refunds			73.4		34.1			30.5
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			14.8		30.4			3
	Accrued dividends on unvested equity awards			0.6		1.6			2.7
	Badlands contingent consideration recorded at acquisition date			-		-			15.3
	Change in capital accruals			19		(0.4	)		(34.3	)
	Transfers from materials and supplies to property, plant and equipment			4.6		20.5			-
	Change in ARO estimate			2.1		1.6			(1.0	)
	___________
	-1	Interest capitalized on expansion projects was $16.1 million, $28.0 million and $13.6 million for the years ended December 31, 2014, 2013 and 2012.

Stock_and_Other_Compensation_P1

Stock and Other 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 the Partnership’s Directors for the years ended December 31, 2014, 2013 and 2012 (in units and dollars):
			Number of units				Weighted Average 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 compensation plans recognized for the years indicated:
			2014				2013			2012
	2010 TRC Stock Incentive Plan - Director Grants		$	0.5			$	0.5		$	0.4
	Partnership Equity-Settled Performance Units			8.8				5.5			3.1
	Partnership Director Grants			0.4				0.5			0.5
	Allocated to the Partnership
	2010 TRC Stock Incentive Plan - Restricted Stock			2.2				6.3			13.7
	2010 TRC Stock Incentive Plan - Restricted Stock Unit			2.5				0.4			-
	TRC LTIP - Cash-Settled Performance Units			11				21.9			14.2
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 compensation plans as of December 31, 2014:
						Weighted Average
		December 31,				Remaining
		2014				Vesting Period
		(In millions)				(In years)
	Partnership 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
	TRC Cash-Settled Performance Units		$	14.7			$	25.2		$	22.2
	Partnership Equity - Settled Performance Units			10				-			-
	Accrued DERs settled for Equity - Settled Performance Units			1.6				-			-
	Partnership Director Grants			0.4				0.7			1
	2010 TRC Stock Incentive Plan - Restricted Stock (1)			7.1				42.2			40.3
	2010 TRC Stock Incentive Plan - Director Grants			0.5				0.5			0.4
	Accrued dividends settled			0.5				2.4			2
	________
	-1	We recognized $1.0 million, $1.6 million and $1.3 million in tax benefits associated with the vesting of the restricted stock in 2014, 2013 and 2012.
Equity-Settled Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Performance Units	The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2014, 2013, and 2012:
			Number				Weighted Average Grant-Date Fair Value
			of units
	Outstanding at December 31, 2011			135,870			$	33.94
	Granted			171,750				41.94
	Outstanding at December 31, 2012			307,620				38.4
	Granted			244,578				46.54
	Outstanding at December 31, 2013			552,198				42.01
	Granted			168,495				57.19
	Vested			(137,170	)			34.02
	Forfeited			(6,120	)			49.39
	Outstanding at December 31, 2014			577,403				48.26
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 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, 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 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 Information [Abstract]
Information by Segment	Segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities.
			Year Ended December 31, 2014
			Field			Coastal
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	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	)	$	-		$	(0.1	)	$	1,136.50
	Other financial information:
	Total assets (1)		$	3,409.00		$	367.2		$	1,717.30		$	708.5	$	60.2		$	115		$	76.3		$	6,453.50
	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
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	Revenues
	Sales of commodities		$	188.8		$	305		$	140.5		$	5,072.40	$	21.4		$	0.1		$	(0.2	)	$	5,728.00
	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			-			(0.2	)		6,314.70
	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	)	$	(0.2	)	$	6,314.70
	Operating margin		$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	(0.3	)	$	801.2
	Other financial information:
	Total assets		$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	77.2		$	6,048.60
	Capital expenditures		$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	-		$	1,034.50
			Year Ended December 31, 2012
			Field			Coastal
			Gathering			Gathering						Marketing					Corporate
			and			and			Logistics			and					and			TRC Non-
			Processing			Processing			Assets			Distribution		Other			Eliminations			Partnership			Total
	Revenues
	Sales of commodities		$	172.7		$	240.6		$	184.4		$	4,680.20	$	41.1		$	-		$	2.1		$	5,321.10
	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	)		2.1			5,679.00
	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	)	$	2.1		$	5,679.00
	Operating margin		$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	1.9		$	693.6
	Other financial information:
	Total assets		$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	79.3		$	5,105.00
	Capital expenditures		$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	0.3		$	617
	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	)		21.5			44.3
				7,595.20			5,728.00			5,321.10
	Fees from midstream services
	Fractionating and treating			208.9			133.9			110.1
	Storage, terminaling, transportation and export			548			280.3			162.5
	Gathering and processing			196.9			114.1			45
	Other			67.5			58.4			40.3
				1,021.30			586.7			357.9
	Total revenues		$	8,616.50		$	6,314.70			5,679.00
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		$	1,136.50		$	801.2		$	693.6
	Depreciation and amortization expense			(351.0	)		(271.9	)		(197.6	)
	General and administrative expense			(148.0	)		(151.5	)		(139.8	)
	Interest expense, net			(147.1	)		(134.1	)		(120.8	)
	Other, net			0.6			5.8			(39.2	)
	Income tax expense			(68.0	)		(48.2	)		(36.9	)
	Net income		$	423		$	201.3		$	159.3

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
		Quarter		Quarter		Quarter		Quarter		Total
		(In millions, except per share 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		158.4		150.3		168.7		163.1		640.5
	Net income		106.9		103.2		120.4		92.5		423
	Net income attributable to Targa / common shareholders		19.6		26.4		30.7		25.6		102.3
	Net income per common share - basic	$	0.47	$	0.63	$	0.73	$	0.61	$	2.44
	Net income per common share - diluted	$	0.47	$	0.63	$	0.73	$	0.61	$	2.43
	2013
	Revenues	$	1,373.80	$	1,370.50	$	1,466.00	$	2,104.40	$	6,314.70
	Gross margin		260.3		265.2		297		355		1,177.50
	Operating income		73.9		60.9		88.5		144.9		368.2
	Net income		33.8		22.5		49.4		95.6		201.3
	Net income attributable to Targa / common shareholders		13.4		15		16.3		20.4		65.1
	Net income per common share - basic	$	0.32	$	0.36	$	0.39	$	0.49	$	1.56
	Net income per common share - diluted	$	0.32	$	0.36	$	0.39	$	0.48	$	1.55

Condensed_Parent_Only_Financia1

Condensed Parent Only Financial Statements (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Parent Only Financial Statements [Abstract]
Condensed Financial Statements	A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual Report.
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED BALANCE SHEETS
		December 31,
		2014			2013
		(In millions)
	ASSETS
	Investment in consolidated subsidiaries	$	243.8		$	208.4
	Deferred income taxes		27.9			23.9
	Long-term debt issue costs		1			1.4
	Total assets	$	272.7		$	233.7
	LIABILITIES AND STOCKHOLDERS' EQUITY
	Accrued current liabilities	$	0.6		$	0.6
	Long-term debt		102			84
	Other long-term liabilities		0.3			0.3
	Commitments and contingencies
	Targa Resources Corp. stockholders' equity		169.8			148.8
	Total liabilities and stockholders' equity	$	272.7		$	233.7
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED STATEMENTS OF OPERATIONS
		Year Ended December 31,
		2014			2013			2012
		(In millions, except per share amounts)
	Equity in net income (loss) of consolidated subsidiaries	$	109.8		$	72.6		$	45.4
	General and administrative expenses		(8.3	)		(8.4	)		(8.2	)
	Income (loss) from operations		101.5			64.2			37.2
	Other income (expense):
	Gain on debt extinguishment		-			-			0.2
	Interest expense		(3.2	)		(3.2	)		(3.2	)
	Income (loss) before income taxes		98.3			61			34.2
	Deferred income tax (expense) benefit		4			4.1			3.9
	Net income (loss) available to common shareholders	$	102.3		$	65.1		$	38.1
	Net income (loss) available per common share - basic	$	2.44		$	1.56		$	0.93
	Net income (loss) available per common share - diluted	$	2.43		$	1.55		$	0.91
	Weighted average shares outstanding - basic		42			41.6			41
	Weighted average shares outstanding - diluted		42.1			42.1			41.8
	TARGA RESOURCES CORP.
	PARENT ONLY
	CONDENSED STATEMENTS OF CASH FLOWS
		Year Ended December 31,
		2014			2013			2012
		(In millions)
	Net cash provided by operating activities	$	(1.3	)	$	(4.1	)	$	0.8
	Investing activities:
	Distribution and return of advances from consolidated subsidiaries		97.3			101.6			78.6
	Net cash provided by investing activities		97.3			101.6			78.6
	Financing activities:
	Long-term debt borrowings		92			65			90
	Long-term debt repayments		(74.0	)		(63.0	)		(96.8	)
	Costs incurred in connection with financing arrangements		-			-			(1.0	)
	Repurchase of common stock		-			(13.3	)		(9.5	)
	Dividends to common and common equivalent shareholders		(113.0	)		(87.8	)		(62.2	)
	Excess tax benefit from stock-based awards		(1.0	)		1.6			1.3
	Distribution to owners		-			-			(1.2	)
	Net cash used in financing activities		(96.0	)		(97.5	)		(79.4	)
	Net increase (decrease) in cash and cash equivalents		-			-			-
	Cash and cash equivalents - beginning of year		-			-			-
	Cash and cash equivalents - end of year	$	-		$	-		$	-

Basis_of_Presentation_Details

Basis of Presentation (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
Partnership Ownership Disclosure [Abstract]
Ownership interest in Partnership by general partner (in hundredths)									2.00%
Parent's ownership interest in the general partner of the Partnership (in hundredths)	100.00%								100.00%
Number of Partnership common units owned (in units)	12,945,659								12,945,659
Ownership interest in Partnership by limited partner (in hundredths)									10.90%
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues	$2,032.90	$2,288.30	$2,000.60	$2,294.70	$2,104.40	$1,466	$1,370.50	$1,373.80	$8,616.50	$6,314.70	$5,679
Product purchases									7,046.90	5,137.20	4,672.30
As Reported [Member]
Revision of Previously Reported Revenues and Product Purchases [Abstract]
Revenues										6,556	5,885.70
Product purchases										5,378.50	4,879
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										6,314.70	5,679
Product purchases										$5,137.20	$4,672.30

Business_Acquisitions_Details

Business Acquisitions (Details) (USD $)	0 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended		0 Months Ended
	Oct. 13, 2014	Dec. 31, 2014	Jan. 31, 2015	Dec. 31, 2013	Dec. 31, 2012	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
Ownership interest in Partnership by limited partner (in hundredths)		10.90%
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]
Term of loan		5 years
Aggregate principal amount			670,000,000
Senior Secured Term Loan [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Term of loan		7 years
Aggregate principal amount			430,000,000
5% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Aggregate principal amount			1,100,000,000
Targa Resources Partners LP [Member] | 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
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					5,909,900,000
Net income					129,500,000
Less: Net income attributable to noncontrolling interests					83,500,000
Net income attributable to Targa Resources Corp.					46,000,000
Net income per common share - Basic (in dollars per share)					$1.12
Net income per common share - Diluted (in dollars per share)					$1.10
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] | Revolving Credit Facility [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] | 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 common unit)		$1.26
Preferred units, cumulative cash distribution		126,500,000
Atlas Pipeline Partners [Member] | Targa Resources Partners LP [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
Amount to be received per $1,000 principal by APL noteholders pursuant to Change of Control Offer			1,010
Atlas Pipeline Partners [Member] | Targa Resources Partners LP [Member] | 4 3/4% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Percentage of tenders received from noteholders (in hundredths)							98.30%
Aggregate principal amount							400,000,000
Interest rate on senior notes (in hundredths)							4.75%
Maturity date		31-Dec-21
Atlas Pipeline Partners [Member] | Targa Resources Partners LP [Member] | 5 7/8% Notes [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Percentage of tenders received from noteholders (in hundredths)							91.60%
Aggregate principal amount							650,000,000
Interest rate on senior notes (in hundredths)							5.88%
Maturity date		31-Dec-23
Atlas Energy [Member]
Pro forma consolidated results of operations [Abstract]
Ownership interest in Partnership by limited partner (in hundredths)		5.50%
Total distribution of common shares (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] | Revolving Credit Facility [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Term of loan		5 years
Aggregate principal amount			670,000,000
Atlas Energy [Member] | Senior Secured Term Loan [Member] | Subsequent Event [Member]
Pro forma consolidated results of operations [Abstract]
Term of loan		7 years
Aggregate principal amount			$430,000,000
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 common unit)		$9.12

Inventories_Details

Inventories (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Partnership:
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	$6,521.10	$5,758.40
Accumulated depreciation	-1,696.50	-1,408.50
Property, plant and equipment, net	4,824.60	4,349.90
Finite-Lived Intangible Assets [Line Items]
Intangible assets	681.8	681.8
Accumulated amortization	-89.9	-28.4
Intangible assets, net	591.9	653.4
Estimated useful lives	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 lives	15 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	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 lives	5 years
Gathering Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,890.70	1,604.60
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	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 lives	5 years
Terminaling and Storage Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	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 lives	10 years
Transportation Assets [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	149.3	121.5
Other Property, Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Other Property, Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	95.6	89.5
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	399	702.8
Targa Resources Partners LP [Member]
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
Finite-Lived Intangible Assets [Line Items]
Intangible assets	681.8	681.8
Accumulated amortization	-89.9	-28.4
Intangible assets, net	591.9	653.4
Targa Resources Partners LP [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,588.60	2,230.10
Targa Resources Partners LP [Member] | Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,884.10	1,598
Targa Resources Partners LP [Member] | Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,038.90	715.2
Targa Resources Partners LP [Member] | Transportation Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	359	294.7
Targa Resources Partners LP [Member] | Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	149.1	121.3
Targa Resources Partners LP [Member] | Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	95.6	89.5
Targa Resources Partners LP [Member] | Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	399	702.8
TRC Non-Partnership [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	6.8	6.8
Accumulated depreciation	-6.8	-2.3
Property, plant and equipment, net	0	4.5
Finite-Lived Intangible Assets [Line Items]
Intangible assets	0	0
Accumulated amortization	0	0
Intangible assets, net	0	0
TRC Non-Partnership [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0	0
TRC Non-Partnership [Member] | Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	6.6	6.6
TRC Non-Partnership [Member] | Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0	0
TRC Non-Partnership [Member] | Transportation Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0	0
TRC Non-Partnership [Member] | Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0.2	0.2
TRC Non-Partnership [Member] | Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0	0
TRC Non-Partnership [Member] | Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$0	$0

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	$50.90	$45.30	$42.30
Change in cash flow estimate	2.1	1.6	-1
Accretion expense	4.5	4	4
Retirement of ARO	-0.2	0	0
End of period	$57.30	$50.90	$45.30

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
Activity related to unconsolidated interest in Gulf Coast Fractionators LP ("GCF") [Roll Forward]
Beginning of period	$55.90
Equity earnings	18		14.8		1.9
End of period	50.2		55.9
Distributions received in excess of Partnership's share of cumulative earnings	5.7		0		0.5
Gulf Coast Fractionators LP [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)	38.80%
Activity related to unconsolidated interest in Gulf Coast Fractionators LP ("GCF") [Roll Forward]
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
Distributions received in excess of Partnership's share of cumulative earnings	$5.70				$0.50
[1]	Includes $5.7 million and $0.5 million distributions received in excess of the Partnership's share of cumulative earnings for the years ended December 31, 2014 and 2012. They 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	$529.60
Other goods and services	111.1	126.1
Interest	37.3	36
Compensation and benefits	46.1	40.2
Income and other taxes	11.7	10.1
Other	15.6	19.8
Accounts payable and accrued liabilities	638.5	761.8
Targa Resources Partners LP [Member]
Components of accounts payable and accrued liabilities [Abstract]
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
Accounts payable and accrued liabilities	592.7	721.2
TRC Non Partnership [Member]
Components of accounts payable and accrued liabilities [Abstract]
Commodities	0	-0.1
Other goods and services	2.2	1.4
Interest	0	0.1
Compensation and benefits	44.8	38.9
Income and other taxes	-1.9	-0.8
Other	0.7	1.1
Accounts payable and accrued liabilities	$45.80	$40.60

Debt_Obligations_Details

Debt Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Oct. 31, 2012
Long-term [Abstract]
Long-term debt	$2,885.40		$2,989.30
Total debt	3,068.20		2,989.30
Letters of credit outstanding	44.1		86.8
Scheduled maturities of debt [Abstract]
Total	3,093.40
2015	182.8
2016	0
2017	102
2018	0
2019	800
After 2019	2,008.60
Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	2,885.40		2,989.30
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | 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] | Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member]
Current Partnership [Abstract]
Current debt	182.8	[1],[2]	0	[1],[2]
TRC Senior Secured Revolving Credit Facility due 2017 [Member]
Long-term [Abstract]
Long-term debt	102	[3]	84	[3]
Maturity date	31-Oct-17	[3]
Line of credit facility, maximum borrowing capacity	150
Availability of credit under senior secured credit facility	48
TRC Senior Secured Revolving Credit Facility due 2017 [Member] | Secured Debt [Member]
Scheduled maturities of debt [Abstract]
Total	102
2015	0
2016	0
2017	102
2018	0
2019	0
After 2019	0
TRC Senior Secured Revolving Credit Facility due 2017 [Member] | Secured Debt [Member] | Irrevocable Standby Letter of Credit [Member]
Long-term [Abstract]
Letters of credit outstanding	0	[3]	0	[3]
TRP Senior Secured Revolving Credit Facility due 2017 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Availability of credit under senior secured credit facility	1,155.90
TRP Senior Secured Revolving Credit Facility due 2017 [Member] | Targa Resources Partners LP [Member] | Secured Debt [Member]
Long-term [Abstract]
Long-term debt	0	[1],[4]	395	[1],[4]
Maturity date	31-Oct-17	[1],[4]
Scheduled maturities of debt [Abstract]
Total	0
2015	0
2016	0
2017	0
2018	0
2019	0
After 2019	0
TRP Senior Secured Revolving Credit Facility due 2017 [Member] | Targa Resources Partners LP [Member] | Secured Debt [Member] | Irrevocable Standby Letter of Credit [Member]
Long-term [Abstract]
Letters of credit outstanding	44.1	[3]	86.8	[3]
Senior Unsecured 7 7/8% Notes due October 2018 [Member] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	0	[1],[5]	250	[1],[5]
Maturity date	31-Oct-18	[1],[5]
Interest rate on fixed rate debt (in hundredths)	7.88%	[1],[5]
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	483.6	[1]	483.6	[1]
Unamortized discount	-25.2	[1]	-28	[1]
Maturity date	28-Feb-21
Interest rate on fixed rate debt (in hundredths)	6.88%	[1]
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] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	300	[1]	300	[1]
Maturity date	31-Aug-22
Interest rate on fixed rate debt (in hundredths)	6.38%	[1]
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] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	600	[1]	600	[1]
Maturity date	31-May-23
Interest rate on fixed rate debt (in hundredths)	5.25%	[1]
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] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	625	[1]	625	[1]
Maturity date	15-Nov-23
Interest rate on fixed rate debt (in hundredths)	4.25%	[1]
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] | Targa Resources Partners LP [Member] | Unsecured Debt [Member]
Long-term [Abstract]
Long-term debt	800	[1]	0	[1]
Maturity date	15-Nov-19
Interest rate on fixed rate debt (in hundredths)	4.13%	[1]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred (in hundredths)	4.13%
TRP Revolver [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Line of credit facility, maximum borrowing capacity	1,200				1,200
Senior Secured Credit Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred, minimum (in hundredths)	2.90%
Range of interest rates incurred, maximum (in hundredths)	2.90%
Weighted average interest rate incurred (in hundredths)	2.90%
Senior Secured Credit Facility [Member] | Targa Resources Partners LP [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] | Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member]
Long-term [Abstract]
Long-term debt	$0	[1],[2]	$279.70	[1],[2]
Maturity date	31-Dec-14	[1],[2]
[1]	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
[2]	The classification of the Partnership's Accounts Receivable Securitization Facility (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 Consolidated Balance Sheets because the Partnership had the ability and intent to fund the Securitization Facility's borrowings on a long-term basis. As of December 31, 2013, the Partnership 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 its Senior Secured Revolving Credit Facility. As of December 31, 2014, the Partnership intended to fund the Securitization Facility's borrowings solely through further extensions of the termination date of the Securitization Facility, based on its 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 Consolidated Balance Sheets.
[3]	As of December 31, 2014, availability under TRC's $150 million senior secured revolving credit facility was $48.0 million.
[4]	As of December 31, 2014, availability under the Partnership's $1.2 billion senior secured revolving credit facility ("TRP Revolver") was $1,155.9 million.
[5]	The outstanding balance of the 7.875% Notes was redeemed in November 2014. See "The Partnership's Senior Unsecured Notes" below.

Debt_Obligations_TRC_Revolving

Debt Obligations, TRC Revolving Credit Agreement (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Oct. 31, 2012
Senior Secured Revolving Credit Facility due on October 2017 [Member]
TRC Revolving Credit Agreement [Abstract]
Maximum borrowing capacity	$150
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member]
TRC Revolving Credit Agreement [Abstract]
Maximum borrowing capacity		150
Maturity date	3-Oct-17
Additional commitment increase available upon request	100	100
Swing line sub-facility		30
Maximum letters of credit and related outstanding reimbursement obligations		50
Interest rate percentage, minimum (in hundredths)	2.75%
Interest rate percentage, maximum (in hundredths)	3.50%
Maximum consolidated leverage ratio	4
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | Minimum [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	2.75%
Commitment fee percentage (in hundredths)	0.38%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | Maximum [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	3.50%
Commitment fee percentage (in hundredths)	0.50%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | Federal Funds Rate [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	0.50%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | Base Rate [Member] | Minimum [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	1.75%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | Base Rate [Member] | Maximum [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	2.50%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due on October 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member]
TRC Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)	1.00%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2014 [Member]
TRC Revolving Credit Agreement [Abstract]
Maximum borrowing capacity		75
Maturity date	31-Jul-14
Debt issue costs written off	$0.20

Debt_Obligations_TRC_Holdco_Lo

Debt Obligations, TRC Holdco Loan Facility (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2007
Debt Instrument [Line Items]
Proceeds from facility	$2,400	$2,238	$2,595
Repayment of loan facility	2,254.80	2,021.20	1,690.70
Holdco Loan Facility due 2015 [Member]
Debt Instrument [Line Items]
Proceeds from facility				450
Repayment of loan facility			88.8
Debt extinguished			89.3
Pretax loss on extinguishment of debt			0.5
Debt issue costs written off			$0.30

Debt_Obligations_Partnerships_

Debt Obligations, Partnership's Revolving Credit Agreement (Details) (Targa Resources Partners LP [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2012
TRP Revolver [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Maximum borrowing capacity	$1,200			$1,200
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
TRP Revolver [Member] | Minimum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Commitment fee percentage (in hundredths)		0.30%
TRP Revolver [Member] | Maximum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Commitment fee percentage (in hundredths)		0.50%
TRP Revolver [Member] | Federal Funds Rate [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		0.50%
TRP Revolver [Member] | Base Rate [Member] | Minimum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		0.75%
TRP Revolver [Member] | Base Rate [Member] | Maximum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		1.75%
TRP Revolver [Member] | Eurodollar [Member] | Minimum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		1.75%
TRP Revolver [Member] | Eurodollar [Member] | Maximum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		2.75%
TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Basis spread on variable rate (in hundredths)		1.00%
Senior Secured Revolving Credit Facility due July 2015 [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Maximum borrowing capacity				1,100
Maturity date	31-Jul-15
Partial write-off of deferred debt issue costs related to amendments			1.7
Letters of Credit [Member] | TRP Revolver [Member] | Minimum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Interest rate percentage (in hundredths)		1.75%
Letters of Credit [Member] | TRP Revolver [Member] | Maximum [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Interest rate percentage (in hundredths)		2.75%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]
The Partnership's Revolving Credit Agreement [Abstract]
Partial write-off of deferred debt issue costs related to amendments	$0	0	$1.70

Debt_Obligations_Partnerships_1

Debt Obligations, Partnership's Senior Unsecured Notes (Details) (Targa Resources Partners LP [Member], Unsecured Debt [Member], USD $)	1 Months Ended	12 Months Ended		1 Months Ended			12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Jul. 31, 2013	Dec. 31, 2014		Jun. 30, 2013	Jan. 31, 2012	Oct. 31, 2012	Dec. 31, 2012	Nov. 30, 2012	31-May-13	Oct. 31, 2014	Nov. 30, 2014
Senior Unsecured 11 1/4% Notes due July 2017 [Member]
The Partnership's Senior Unsecured Notes [Abstract]
Premium paid on redemption of debt	$4.10
Debt issue costs written off	1
Debt redeemed	76.8
Pretax loss on extinguishment of debt	-7.4
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
Debt issue costs written off		2.5
Pretax loss on extinguishment of debt		-12.4
Terms of the Senior Unsecured Notes Outstanding [Abstract]
Due date		31-Oct-18	[1],[2]
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		28-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		90 days
Redemption Dates and Prices [Abstract]
Any date prior to		1-Feb-14
Price (in hundredths)		106.88%
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2016 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		103.44%
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2017 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		102.29%
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2018 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		101.15%
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2019 and Thereafter [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.00%
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
Debt issue costs written off				1
Debt redeemed				106.4
Face amount of notes redeemed				100
Pretax 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		31-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		180 days
Redemption Dates and Prices [Abstract]
Any date prior to		1-Feb-15
Price (in hundredths)		106.38%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2017 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		103.19%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2018 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		102.13%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2019 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		101.06%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2020 and Thereafter [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.00%
Senior Unsecured 5 1/4% Notes due May 2023 [Member]
The Partnership's Senior Unsecured Notes [Abstract]
Aggregate principal amount issued						400	200
Percentage of face amount issued (in hundredths)						99.50%	101.00%
Gross proceeds from issuance of notes						398	202
Terms of the Senior Unsecured Notes Outstanding [Abstract]
Issue date		Oct / Dec 2012
Per annum interest rate (in hundredths)		5.25%
Due date		31-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		180 days
Redemption Dates and Prices [Abstract]
Any date prior to		1-Nov-15
Price (in hundredths)		105.25%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2017 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		102.63%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2018 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		101.75%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2019 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.88%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2020 and Thereafter [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.00%
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
Debt issue costs written off								2.5
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		180 days
Redemption Dates and Prices [Abstract]
Any date prior to		15-May-16
Price (in hundredths)		104.25%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2018 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		102.13%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2019 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		101.42%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2020 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.71%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2021 and Thereafter [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.00%
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		180 days
Redemption Dates and Prices [Abstract]
Any date prior to		15-Nov-19
Price (in hundredths)		104.13%
Senior Unsecured, 4 1/8% Notes due November 2019 [Member] | 2016 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		102.06%
Senior Unsecured, 4 1/8% Notes due November 2019 [Member] | 2017 [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		101.03%
Senior Unsecured, 4 1/8% Notes due November 2019 [Member] | 2018 and Thereafter [Member]
Redemption Dates and Prices [Abstract]
Price (in hundredths)		100.00%
[1]	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
[2]	The outstanding balance of the 7.875% Notes was redeemed in November 2014. See "The Partnership's Senior Unsecured Notes" below.

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, 2012	Jul. 31, 2013
	Subsidiary
Debt Instrument [Line Items]
Aggregate amount of debt or equity securities allowed under shelf agreement		$300
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | 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
Revolving Credit Facility [Member] | TRC Holdco Notes [Member]
Debt Re-acquisitions Summary [Abstract]
Write-off of deferred debt issue cost	0	0	0.3
Gain on acquisition of debt	0	0	-0.5
Revolving Credit Facility [Member] | TRC Revolver [Member]
Debt Re-acquisitions Summary [Abstract]
Partial write-off of deferred debt issue costs related to amendments	0	0	0.2
Targa Resources Partners LP [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]
Debt Re-acquisitions Summary [Abstract]
Partial write-off of deferred debt issue costs related to amendments			1.7
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | 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
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]
Debt Re-acquisitions Summary [Abstract]
Partial write-off of deferred debt issue costs related to amendments	$0	$0	$1.70

Debt_Obligations_Subsequent_Ev

Debt Obligations, Subsequent Event (Details) (Subsequent Event [Member], USD $)	12 Months Ended	1 Months Ended
	Dec. 31, 2014	Jan. 31, 2015
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$670,000,000
Aggregate principal amount		670,000,000
Term of loan	5 years
Senior Secured Term Loan [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		430,000,000
Aggregate principal amount		430,000,000
Term of loan	7 years
5% Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		1,100,000,000
Net proceeds from private placement of notes		1,090,800,000
Aggregate principal amount		1,100,000,000
Atlas Energy [Member]
Debt Instrument [Line Items]
Committed financing value		1,100,000,000
Revolving credit facility paid off		150,000,000
Atlas Energy [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		670,000,000
Aggregate principal amount		670,000,000
Term of loan	5 years
Atlas Energy [Member] | Senior Secured Term Loan [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		430,000,000
Aggregate principal amount		$430,000,000
Term of loan	7 years

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	Jan. 31, 2015	Aug. 31, 2012	Mar. 31, 2013	Aug. 31, 2013	31-May-14	Nov. 30, 2012	Jan. 31, 2012	Jul. 31, 2012
Partnership Equity [Abstract]
Number of common units included in public offering (in shares)													7,175,096
Net proceeds from sale of common units													$408.40
General partner contributed to maintain general partner ownership percentage													8.4
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
Commissions to sales agents, maximum (in hundredths)													1.00%
Number of days from end of each quarter by when cash is distributed to unit holders													45 days
Distributions declared and/or paid by Partnership [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 common	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
Distributions to Targa Resources Corp.	51.6	48.9	46.3	44	41.5	38.6	35.9	33	30.7	26.2	24.2	22.2
Distributions per limited partner 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
Subsequent Event [Member]
Partnership Equity [Abstract]
Number of common units included in public offering (in shares)														284,137
Net proceeds from sale of common units														13
General partner contributed to maintain general partner ownership percentage														0.3
Ownership interest in Partnership by general partner (in hundredths)														2.00%
General partner contribution settled amount														1
August 2012 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offering (in shares)															2,420,046
Net proceeds from sale of common units															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 offering (in shares)																4,204,751
Net proceeds from sale of common units																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 offering (in shares)																	4,529,641
Net proceeds from sale of common units																	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
Targa Resources LP [Member] | Shelf Offering 2010 Shelf [Member]
Partnership Equity [Abstract]
Number of common units included in public offering (in shares)																			10,925,000	4,405,000
Per share price on public offering (in dollars per share)																			$36	$38.30
Net proceeds from sale of common units																			378.2	164.8
Number of common units purchased by Company (in units)																				1,300,000
Aggregate value of common units purchased by Company																				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																			$975.80

Common_Stock_and_Related_Matte2

Common Stock and Related Matters (Details) (USD $)

12 Months Ended

3 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

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

Dividends Payable [Line Items]

Amount of dividend paid

$113

$87.80

$62.20

Dividend Declared, Q4 2014 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

17-Feb-15

Total dividend declared

32.8

Amount of dividend paid

32.6

Accrued dividends

0.2

[1]

0.2

[1]

Dividend declared per share of common stock (in dollars per share)

$0.78

Dividend Declared, Q3 2014 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

17-Nov-14

Total dividend declared

31

Amount of dividend paid

30.8

Accrued dividends

0.2

[1]

Dividend declared per share of common stock (in dollars per share)

$0.73

Dividend Declared, Q2 2014 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Aug-14

Total dividend declared

29.2

Amount of dividend paid

29

Accrued dividends

0.2

[1]

Dividend declared per share of common stock (in dollars per share)

$0.69

Dividend Declared, Q1 2014 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

16-May-14

Total dividend declared

27.4

Amount of dividend paid

27.2

Accrued dividends

0.2

[1]

Dividend declared per share of common stock (in dollars per share)

$0.65

Dividend Declared, Q4 2013 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

18-Feb-14

Total dividend declared

25.6

Amount of dividend paid

25.5

Accrued dividends

0.1

[1]

0.1

[1]

Dividend declared per share of common stock (in dollars per share)

$0.61

Dividend Declared, Q3 2013 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Nov-13

Total dividend declared

24.1

Amount of dividend paid

23.7

Accrued dividends

0.4

[1]

Dividend declared per share of common stock (in dollars per share)

$0.57

Dividend Declared, Q2 2013 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Aug-13

Total dividend declared

22.5

Amount of dividend paid

22.1

Accrued dividends

0.4

[1]

Dividend declared per share of common stock (in dollars per share)

$0.53

Dividend Declared, Q1 2013 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

16-May-13

Total dividend declared

21

Amount of dividend paid

20.6

Accrued dividends

0.4

[1]

Dividend declared per share of common stock (in dollars per share)

$0.50

Dividend Declared, Q4 2012 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Feb-13

Total dividend declared

19.4

Amount of dividend paid

19

Accrued dividends

0.4

[1]

0.4

[1]

Dividend declared per share of common stock (in dollars per share)

$0.46

Dividend Declared, Q3 2012 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Nov-12

Total dividend declared

18

Amount of dividend paid

17.3

Accrued dividends

0.7

[1]

Dividend declared per share of common stock (in dollars per share)

$0.42

Dividend Declared, Q2 2012 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

15-Aug-12

Total dividend declared

16.7

Amount of dividend paid

16.1

Accrued dividends

0.6

[1]

Dividend declared per share of common stock (in dollars per share)

$0.39

Dividend Declared, Q1 2012 [Member]

Dividends Payable [Line Items]

Date paid or to be paid

16-May-12

Total dividend declared

15.5

Amount of dividend paid

15

Accrued dividends

$0.50

[1]

Dividend declared per share of common stock (in dollars per share)

$0.37

[1]

Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Earnings_per_Common_Share_Deta

Earnings per Common Share (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
Earnings per Common Share [Abstract]
Net income	$92.50	$120.40	$103.20	$106.90	$95.60	$49.40	$22.50	$33.80	$423	$201.30	$159.30
Less: Net income attributable to noncontrolling interests									320.7	136.2	121.2
Net income attributable to common shareholders	$25.60	$30.70	$26.40	$19.60	$20.40	$16.30	$15	$13.40	$102.30	$65.10	$38.10
Weighted average shares outstanding - basic (in shares)									42	41.6	41
Net income available per common share - basic (in dollars per share)	$0.61	$0.73	$0.63	$0.47	$0.49	$0.39	$0.36	$0.32	$2.44	$1.56	$0.93
Weighted average shares outstanding (in shares)									42	41.6	41
Dilutive effect of unvested stock awards (in shares)									0.1	0.5	0.8
Weighted average shares outstanding - diluted (in shares)									42.1	42.1	41.8
Net income available per common share - diluted (in dollars per share)	$0.61	$0.73	$0.63	$0.47	$0.48	$0.39	$0.36	$0.32	$2.43	$1.55	$0.91

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
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		$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]
Gain (loss) reclassified from OCI into income (effective portion)	($6.60)		$14.90		$38.10
Net losses on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months	44.3
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
Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	-4.2		21		46
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Deferred gains (losses) included in accumulated OCI, before tax	60.3	[1]	-3.7	[1]
Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Deferred gains (losses) included in accumulated OCI, before tax	0		-2.4
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	59.7		-5.8		76.8
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	59.7		-5.8		76.8
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]
Derivative 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
Liabilities from commodity derivative contracts	0.8		6.8
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Contingent consideration			50
Commodity Derivative Contracts Liability/ (Asset) [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
Issuances				0
Settlements included in Revenue	-0.2		-1.3	-0.1
Unrealized (gains) losses included in OCI	-1.1			0.7
Transfers out of Level 3	0.3
Debt extinguishment				0
Change in valuation of contingent liability included in Other Income			0
Balance, end of period	-1.7		-0.7	0.6
Long-Term Debt [Member]
Changes in fair value of financial instruments classified as Level 3 in the fair value hierarchy [Roll Forward]
Balance, beginning of period	0		0	87.5
Issuances				0
Settlements included in Revenue	0		0	0
Unrealized (gains) losses included in OCI	0			0
Transfers out of Level 3	0
Debt extinguishment				-87.5
Change in valuation of contingent liability included in Other Income			0
Balance, end of period	0		0	0
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
Issuances				15.3
Settlements included in Revenue	0		0	0
Unrealized (gains) losses included in OCI	0			0
Transfers out of Level 3	0
Debt extinguishment				0
Change in valuation of contingent liability included in Other Income			-15.3
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
Liabilities from commodity derivative contracts	5.2	[1]	9.4
Badlands contingent consideration liability			0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	81		66.7
Carrying Value [Member] | TRC Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	102		84
Carrying Value [Member] | Partnership's 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] | Partnership's 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] | Partnership's 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]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	60.2	[1]	5.1
Liabilities from commodity derivative contracts	5.2	[1]	9.4
Badlands contingent consideration liability			0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	81		66.7
Fair Value [Member] | TRC Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	102		84
Fair Value [Member] | Partnership's 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] | Partnership's 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] | Partnership's 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 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	0	[1]	0
Liabilities from commodity derivative contracts	0	[1]	0
Badlands contingent consideration liability			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] | TRC 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] | Partnership's 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] | Partnership's 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] | Partnership's Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	0		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
Liabilities from commodity derivative contracts	5.1	[1]	8.4
Badlands contingent consideration liability			0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	0		0
Fair Value [Member] | Level 2 [Member] | TRC Senior Secured Revolving Credit Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	102		84
Fair Value [Member] | Level 2 [Member] | Partnership's 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] | Partnership's 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] | Partnership's 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
Liabilities from commodity derivative contracts	0.1	[1]	1
Badlands contingent consideration liability			0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents	0		0
Fair Value [Member] | Level 3 [Member] | TRC 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] | Partnership's 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] | Partnership's 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] | Partnership's Accounts Receivable Securitization Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt	$0		$0
[1]	The fair value of the derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14. 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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Gulf Coast Fractionators LP [Member]
Related Party Transaction [Line Items]
Revenues	$0.80	$0.40	$0.10
Costs and expenses	7.6	6.3	1.9
SAJET Resources LLC [Member]
Related Party Transaction [Line Items]
Amount reimbursed to related parties during period	1.4
Tesla Resources LLC [Member]
Related Party Transaction [Line Items]
Amount reimbursed to related parties during period	$0.20

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	$46
2015	12.1
2016	12.1
2017	10.4
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	7.6	[1]
2015	2.4	[1]
2016	2.7	[1]
2017	2.5	[1]
2018	0	[1]
2019	0	[1]
Total expenses on lease obligations	3.3		2.8		2.1
Targa Resources Partners LP [Member] | Operating Leases [Member]
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract]
In aggregate	28.9	[2]
2015	7.7	[2]
2016	7.4	[2]
2017	5.9	[2]
2018	4.6	[2]
2019	3.3	[2]
Total expenses on lease obligations	24.4	[3]	23.3	[3]	16.1	[3]
Targa Resources Partners LP [Member] | 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	[4]
2015	2	[4]
2016	2	[4]
2017	2	[4]
2018	1.8	[4]
2019	1.7	[4]
Total expenses on lease obligations	$4.10		$3.60		$3.30
[1]	Includes minimum payments on lease obligation for corporate office space.
[2]	Includes minimum payments on lease obligations for office space, railcars and tractors.
[3]	Includes short-term leases for items such as compressors and equipment.
[4]	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 the Partnership. These agreements expire at various dates, with varying terms, some of which are perpetual.

Contingencies_Details

Contingencies (Details) (Atlas Unitholder Litigation [Member])	3 Months Ended	2 Months Ended
	Dec. 31, 2014	Nov. 30, 2014
	Unitholder	Unitholder
Atlas Pipeline Partners [Member]
Loss Contingencies [Line Items]
Number of public unitholders	5
Atlas Energy [Member]
Loss Contingencies [Line Items]
Number of public unitholders		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	1.1	0.9	2.4
Additions	0	0.2	0
Deductions	-1.1	0	-1.5
Balance at end of year	$0	$1.10	$0.90
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
Total 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 the Partnership's investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Provisions for income taxes [Abstract]
Current expense	$72.40		$42.80		$27.90
Deferred expense (benefit)	-4.4		5.4		9
Income tax provision	68		48.2		36.9
Deferred tax assets [Abstract]
Deferred tax assets before valuation allowance	3.5		3.5
Valuation allowance	-3.5		-3.5
Total deferred tax asset	0		0
Deferred tax liabilities [Abstract]
Investments	-115.8	[1]	-115.2	[1]
Debt related deferreds	-13.4		-17.2
Other	-9.5		-7.1
Total deferred tax liability	-138.7		-139.5
Net deferred tax liability	-138.7		-139.5
Net deferred tax liability [Abstract]
Federal	-115.5		-121
Foreign	0.6		0.6
State	-23.8		-19.1
Net deferred tax liability	-138.7		-139.5
Balance sheet classification of deferred tax assets (liabilities) [Abstract]
Long-term asset	0		-3.5
Current liability	-0.5		-0.5
Long-term liability	-138.2		-135.5
Net deferred tax liability	-138.7		-139.5
Income tax reconciliation [Abstract]
Income before income taxes	491		249.5		196.2
Less: Net income attributable to noncontrolling interests	-320.7		-136.2		-121.2
Less: Income taxes included in noncontrolling interest	-4.2		-2.5		-3.5
Income attributable to TRC before income taxes	166.1		110.8		71.5
Federal statutory income tax rate (in hundredths)	35.00%		35.00%		35.00%
Provision for federal income taxes	58.1		38.8		25
State income taxes, net of federal tax benefit	6.7		4.4		6.8
Amortization of deferred charge on 2010 transactions	4.7		4.7		4.7
Other, net	-1.5		0.3		0.4
Income tax provision	$68		$48.20		$36.90
[1]	Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our investments.

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	$133.80	[1]	$121.70	[1]	$95.60	[1]
Income taxes paid, net of refunds	73.4		34.1		30.5
Non-cash:
Deadstock inventory transferred to property, plant and equipment	14.8		30.4		3
Accrued dividends on unvested equity awards	0.6		1.6		2.7
Badlands contingent consideration recorded at acquisition date	0		0		15.3
Change in capital accruals	19		-0.4		-34.3
Transfers from materials and supplies to property, plant and equipment	4.6		20.5		0
Change in ARO estimate	2.1		1.6		-1
Interest capitalized on expansion projects	$16.10		$28		$13.60
[1]	Interest capitalized on expansion projects was $16.1 million, $28.0 million and $13.6 million for the years ended December 31, 2014, 2013 and 2012.

Stock_and_Other_Compensation_P2

Stock and Other Compensation Plans (Details) (USD $)	12 Months Ended						0 Months Ended					1 Months Ended	0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Jan. 21, 2015	Jan. 12, 2015	Aug. 22, 2014	Aug. 01, 2014	Feb. 14, 2014	Jan. 31, 2015	Jan. 15, 2015
401(k) Plan [Abstract]
Description of 401(k) plan	We have a 401(k) plan whereby we match 100% of up to 5% of an employeebs contribution (subject to certain limitations in the plan). We also contribute 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. We 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
Equity-Settled Performance Units [Member] | Subsequent Event [Member]
Nonvested, number of shares/ units [Roll Forward]
Granted (in shares)							103,760
Cash-Settled Performance Units [Member]
Nonvested, number of shares/ units [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 [Roll Forward]
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
Weighted average recognition period for unrecognized compensation cost	1 year 8 months 12 days
Restricted Stock Units (RSUs) [Member]
Nonvested, number of shares/ units [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 [Roll Forward]
Outstanding, beginning period (in dollars per share)	$69.92		$0
Granted (in dollars per shares)	$112.89		$69.90
Vested/ 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
Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member]
Weighted-average grant-date fair value [Roll Forward]
Stock repurchased from employees (in shares)								5,930
Stock repurchase price (in dollars per share)								$89.27
Accrued Dividends Settled [Member]
Weighted-average grant-date fair value [Roll Forward]
Fair value of units vested during the period	0.5		2.4		2
Partnership Long-term Incentive Plan [Member] | Equity-Settled Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total units authorized (in shares)	1,680,000
Nonvested, number of shares/ units [Roll Forward]
Outstanding, beginning of period (in shares)	552,198		307,620		135,870
Granted (in shares)	168,495		244,578		171,750
Vested/ Vested and paid (in shares)	-137,170
Forfeited (in shares)	-6,120
Outstanding, end of period (in shares)	577,403		552,198		307,620
Weighted-average grant-date fair value [Roll Forward]
Outstanding, beginning period (in dollars per share)	$42.01		$38.40		$33.94
Granted (in dollars per shares)	$57.19		$46.54		$41.94
Vested/ Vested and paid (in dollars per share)	$34.02
Forfeited (in dollars per share)	$49.39
Outstanding, end of period (in dollars per share)	$48.26		$42.01		$38.40
Vesting period of awards (in years)	3 years
To be recognized in future periods	14.1
Weighted average recognition period for unrecognized compensation cost	2 years
Compensation expense recognized	8.8		5.5		3.1
Fair value of units vested during the period	10		0		0
Partnership Long-term Incentive Plan [Member] | Director Grants [Member] | Non-Management Directors [Member] | Subsequent Event [Member]
Nonvested, number of shares/ units [Roll Forward]
Granted (in shares)							10,565
Weighted-average grant-date fair value [Roll Forward]
Units granted per individual (in units)							2,113
2011 Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of shares/ units [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 shares/ units [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 [Roll Forward]
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	June, 2015
2013 Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of shares/ units [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 [Roll Forward]
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	June, 2016
2014 Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Nonvested, number of shares/ units [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 [Roll Forward]
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	June, 2017
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total units authorized (in shares)	5,000,000
Nonvested, number of shares/ units [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 [Roll Forward]
Outstanding, beginning period (in dollars per share)	$41.05		$25.95		$22.67
Granted (in dollars per shares)	$0		$57.59	[1]	$42.50	[1]
Vested/ 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
Vesting percentage of IPO stock awards over 24 months (in hundredths)			40.00%
Vesting percentage of IPO stock awards in year three (in hundredths)			60.00%
Stock repurchased from employees (in shares)			169,159		197,731				1,006	12,849	8,113
Stock repurchase price (in dollars per share)			$79.01		$47.88				$137.64	$129.46	$96.52
Vesting period of awards (in years)	3 years
To be recognized in future periods	1.1
Weighted average recognition period for unrecognized compensation cost	0 years 10 months 24 days
Fair value of units vested during the period	7.1	[4]	42.2	[4]	40.3	[4]
Recognized tax benefits	1		1.6		1.3
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | Subsequent Event [Member]
Nonvested, number of shares/ units [Roll Forward]
Granted (in shares)												32,372
Weighted-average grant-date fair value [Roll Forward]
Vesting period of awards (in years)												3 years
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | Targa Resources Partners LP [Member]
Weighted-average grant-date fair value [Roll Forward]
Compensation expense recognized	2.2		6.3		13.7
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Weighted-average grant-date fair value [Roll Forward]
To be recognized in future periods	7
Weighted average recognition period for unrecognized compensation cost	2 years 3 months 18 days
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Targa Resources Partners LP [Member]
Weighted-average grant-date fair value [Roll Forward]
Compensation expense recognized	2.5		0.4		0
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member]
Weighted-average grant-date fair value [Roll Forward]
Compensation expense recognized	0.5		0.5		0.4
Fair value of units vested during the period	0.5		0.5		0.4
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member] | Subsequent Event [Member]
Nonvested, number of shares/ units [Roll Forward]
Granted (in shares)													5,862
TRC Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member]
Weighted-average grant-date fair value [Roll Forward]
Compensation expense recognized	11		21.9		14.2
Fair value of units vested during the period	14.7		25.2		22.2
Director Grants and Incentive Plan [Member]
Nonvested, number of shares/ units [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 [Roll Forward]
Outstanding, beginning period (in dollars per share)	$0		$23.51		$16.31
Granted (in dollars per shares)	$50.29		$39.33		$38.72
Vested/ 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
Compensation expense recognized	0.4		0.5		0.5
Fair value of units vested during the period	0.4		0.7		1
Accrued DERs Settled [Member] | Equity-Settled Performance Units [Member]
Weighted-average grant-date fair value [Roll Forward]
Fair value of units vested during the period	$1.60		$0		$0
[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]	We recognized $1.0 million, $1.6 million and $1.3 million tax benefits associated with the vesting of the restricted in 2014, 2013 and 2012.

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
										Division
Segment Reporting Information [Line Items]
Number of divisions										2
Sale of commodities										$7,595.20		$5,728	$5,321.10
Fees from midstream services										1,021.30		586.7	357.9
Revenues	2,032.90		2,288.30	2,000.60	2,294.70	2,104.40	1,466	1,370.50	1,373.80	8,616.50		6,314.70	5,679
Operating margin										1,136.50		801.2	693.6
Other financial information [Abstract]
Total assets	6,453.50	[1]				6,048.60				6,453.50	[1]	6,048.60	5,105
Capital expenditures										747.8		1,034.50	617
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] | Targa Resources Partners LP [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] | Targa Resources Partners LP [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] | Targa Resources Partners LP [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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues										7,971.50		5,804.10	5,401.40
Operating margin										249.6		141.9	116
Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues										-2,903.50		-2,554.30	-2,558.60
Operating margin										0		0	0
TRC Non-Partnership [Member]
Segment Reporting Information [Line Items]
Revenues										0		-0.2	2.1
Operating margin										-0.1		-0.3	1.9
Other financial information [Abstract]
Total assets	76.3	[1]				77.2				76.3	[1]	77.2	79.3
Capital expenditures										0		0	0.3
Business acquisitions													0
Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues										-8		21.4	41.1
Operating margin										-8		21.4	41.1
Operating Segments [Member]
Segment Reporting Information [Line Items]
Sale of commodities										7,595.20		5,728	5,321.10
Fees from midstream services										1,021.30		586.7	357.9
Revenues										8,616.50		6,314.70	5,679
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities										0		0.1	0
Fees from midstream services										0		-0.1	-0.1
Revenues										0		0	-0.1
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] | TRC Non-Partnership [Member]
Segment Reporting Information [Line Items]
Sale of commodities										0		-0.2	2.1
Fees from midstream services										0		0	0
Revenues										0		-0.2	2.1
Operating Segments [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities										-8		21.4	41.1
Fees from midstream services										0		0	0
Revenues										-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
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale 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
Intersegment Eliminations [Member] | TRC Non-Partnership [Member]
Segment Reporting Information [Line Items]
Sale of commodities										0		0	0
Fees from midstream services										0		0	0
Revenues										0		0	0
Intersegment Eliminations [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities										0		0	0
Fees from midstream services										0		0	0
Revenues										$0		$0	$0
[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]
Sale of commodities									$7,595.20	$5,728	$5,321.10
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	2,104.40	1,466	1,370.50	1,373.80	8,616.50	6,314.70	5,679
Reconciliation of operating margin to net income [Abstract]
Operating margin									1,136.50	801.2	693.6
Depreciation and amortization expenses									-351	-271.9	-197.6
General and administrative expenses									-148	-151.5	-139.8
Interest expense, net									-147.1	-134.1	-120.8
Other, net									0.6	5.8	-39.2
Income tax expense									-68	-48.2	-36.9
Net income	92.5	120.4	103.2	106.9	95.6	49.4	22.5	33.8	423	201.3	159.3
Natural Gas Sales [Member]
Revenue from External Customer [Line Items]
Sale of commodities									1,409.30	1,224.70	926.9
NGL Sales [Member]
Revenue from External Customer [Line Items]
Sale of commodities									5,960.10	4,224	4,055.70
Condensate Sales [Member]
Revenue from External Customer [Line Items]
Sale of commodities									134.3	121.8	114.1
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sale of commodities									96.3	136	180.1
Derivative Settlements [Member]
Revenue from External Customer [Line Items]
Sale of commodities									-4.8	21.5	44.3
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	280.3	162.5
Gathering and Processing Fees [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									$67.50	$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	$2,104.40	$1,466	$1,370.50	$1,373.80	$8,616.50	$6,314.70	$5,679
Gross margin	398.2	407.8	384	379.6	355	297	265.2	260.3	1,569.60	1,177.50
Operating income	163.1	168.7	150.3	158.4	144.9	88.5	60.9	73.9	640.5	368.2	336.3
Net income	92.5	120.4	103.2	106.9	95.6	49.4	22.5	33.8	423	201.3	159.3
Net income attributable to Targa / common shareholders	$25.60	$30.70	$26.40	$19.60	$20.40	$16.30	$15	$13.40	$102.30	$65.10	$38.10
Net income per common share - basic (in dollars per share)	$0.61	$0.73	$0.63	$0.47	$0.49	$0.39	$0.36	$0.32	$2.44	$1.56	$0.93
Net income per common share - diluted (in dollars per share)	$0.61	$0.73	$0.63	$0.47	$0.48	$0.39	$0.36	$0.32	$2.43	$1.55	$0.91

Condensed_Parent_Only_Financia2

Condensed Parent Only Financial Statements (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
ASSETS [Abstract]
Deferred income taxes	$0					($3.50)				$0		($3.50)
Total assets	6,453.50	[1]				6,048.60				6,453.50	[1]	6,048.60	5,105
LIABILITIES AND STOCKHOLDERS' EQUITY [Abstract]
Long-term debt	2,885.40					2,989.30				2,885.40		2,989.30
Other long-term liabilities	63.3					60.7				63.3		60.7
Commitments and contingencies
Targa Resources Corp. stockholders' equity	169.8					148.8				169.8		148.8
Total liabilities and owners' equity	6,453.50					6,048.60				6,453.50		6,048.60
CONDENSED STATEMENT OF OPERATIONS [Abstract]
Equity in net income (loss) of consolidated subsidiaries										18		14.8	1.9
General and administrative expenses										-148		-151.5	-139.8
Income from operations	163.1		168.7	150.3	158.4	144.9	88.5	60.9	73.9	640.5		368.2	336.3
Other income (expense):
Income before income taxes										491		249.5	196.2
Deferred income tax (expense) benefit										4.4		-5.4	-9
Net income available to common shareholders										102.3		65.1	38.1
Net income (loss) available per common share - basic (in dollars per share)	$0.61		$0.73	$0.63	$0.47	$0.49	$0.39	$0.36	$0.32	$2.44		$1.56	$0.93
Net income (loss) available per common share - diluted (in dollars per share)	$0.61		$0.73	$0.63	$0.47	$0.48	$0.39	$0.36	$0.32	$2.43		$1.55	$0.91
Weighted average shares outstanding - basic (in shares)										42		41.6	41
Weighted average shares outstanding - diluted (in shares)										42.1		42.1	41.8
CONDENSED STATEMENT OF CASH FLOWS [Abstract]
Net cash used in operating activities										761.8		382.7	428.2
Investing activities:
Net cash used in investing activities										-751.4		-1,026.30	-1,590.70
Financing activities:
Costs incurred in connection with financing arrangements										-14.3		-15.3	-36.6
Repurchase of common stock										-2.6		-13.3	-9.5
Dividends to common and common equivalent shareholders										-113		-87.8	-62.2
Excess tax benefit from stock-based awards										1		1.6	1.3
Distribution to owners										-341.4		-274.4	-211.5
Net cash used in financing activities										3.9		634	1,093
Net change in cash and cash equivalents										14.3		-9.6	-69.5
Cash and cash equivalents, beginning of period					66.7				76.3	66.7		76.3	145.8
Cash and cash equivalents, end of period	81					66.7				81		66.7	76.3
Parent Company [Member]
ASSETS [Abstract]
Investment in consolidated subsidiaries	243.8					208.4				243.8		208.4
Deferred income taxes	27.9					23.9				27.9		23.9
Long-term debt issue costs	1					1.4				1		1.4
Total assets	272.7					233.7				272.7		233.7
LIABILITIES AND STOCKHOLDERS' EQUITY [Abstract]
Accrued current liabilities	0.6					0.6				0.6		0.6
Long-term debt	102					84				102		84
Other long-term liabilities	0.3					0.3				0.3		0.3
Commitments and contingencies
Targa Resources Corp. stockholders' equity	169.8					148.8				169.8		148.8
Total liabilities and owners' equity	272.7					233.7				272.7		233.7
CONDENSED STATEMENT OF OPERATIONS [Abstract]
Equity in net income (loss) of consolidated subsidiaries										109.8		72.6	45.4
General and administrative expenses										-8.3		-8.4	-8.2
Income from operations										101.5		64.2	37.2
Other income (expense):
Gain (loss) on early debt extinguishment, net										0		0	0.2
Interest expense										-3.2		-3.2	-3.2
Income before income taxes										98.3		61	34.2
Deferred income tax (expense) benefit										4		4.1	3.9
Net income available to common shareholders										102.3		65.1	38.1
Net income (loss) available per common share - basic (in dollars per share)										$2.44		$1.56	$0.93
Net income (loss) available per common share - diluted (in dollars per share)										$2.43		$1.55	$0.91
Weighted average shares outstanding - basic (in shares)										42		41.6	41
Weighted average shares outstanding - diluted (in shares)										42.1		42.1	41.8
CONDENSED STATEMENT OF CASH FLOWS [Abstract]
Net cash used in operating activities										-1.3		-4.1	0.8
Investing activities:
Distribution and return of advances from consolidated subsidiaries										97.3		101.6	78.6
Net cash used in investing activities										97.3		101.6	78.6
Financing activities:
Long-term debt borrowings										92		65	90
Long-term debt repayments										-74		-63	-96.8
Costs incurred in connection with financing arrangements										0		0	-1
Repurchase of common stock										0		-13.3	-9.5
Dividends to common and common equivalent shareholders										-113		-87.8	-62.2
Excess tax benefit from stock-based awards										-1		1.6	1.3
Distribution to owners										0		0	-1.2
Net cash used in financing activities										-96		-97.5	-79.4
Net change in cash and cash equivalents										0		0	0
Cash and cash equivalents, beginning of period					0				0	0		0	0
Cash and cash equivalents, end of period	$0					$0				$0		$0	$0
[1]	Corporate assets primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our long-term debt