Targa Resources (TRGP) 10-Q 4 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Targa Resources Corp.
Entity Central Index Key	1,389,170
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		56,031,679
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 105.7	$ 81
Trade receivables, net of allowances of $0.0 million	602.5	567.3
Inventories	124.8	168.9
Deferred income taxes	0	0.1
Assets from risk management activities	91.8	44.4
Other current assets	38.7	20.9
Total current assets	963.5	882.6
Property, plant and equipment	11,602	6,521.1
Accumulated depreciation	(1,917.7)	(1,696.5)
Property, plant and equipment, net	9,684.3	4,824.6
Goodwill	557.9	0
Intangible assets, net	1,735.6	591.9
Long-term assets from risk management activities	40.3	15.8
Investments in unconsolidated affiliates	258	50.2
Other long-term assets	113.3	88.4
Total assets	13,352.9	6,453.5
Current liabilities:
Accounts payable and accrued liabilities	689.1	638.5
Accounts receivable securitization facility	124.2	182.8
Deferred income taxes	31.8	0.6
Liabilities from risk management activities	1.9	5.2
Total current liabilities	847	827.1
Long-term debt	5,796.1	2,885.4
Long-term liabilities from risk management activities	5.3	0
Deferred income taxes	133.5	138.2
Other long-term liabilities	$ 78.8	$ 63.3
Contingencies (see Note 16)
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 300,000,000 shares authorized), 56,442,449 shares issued and 56,030,634 shares outstanding as of June 30, 2015, and 42,532,353 shares issued and 42,143,463 shares outstanding as of December 31, 2014.	$ 0.1	$ 0
Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding)	0	0
Additional paid-in capital	1,524.6	164.9
Retained earnings	15.4	25.5
Accumulated other comprehensive income (loss)	3.5	4.8
Treasury stock, at cost (411,815 shares as of June 30, 2015 and 388,890 as of December 31, 2014)	(27.5)	(25.4)
Total Targa Resources Corp. stockholders' equity	1,516.1	169.8
Noncontrolling interests in subsidiaries	4,976.1	2,369.7
Total owners' equity	6,492.2	2,539.5
Total liabilities and owners' equity	$ 13,352.9	$ 6,453.5

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Trade receivables, allowances	$ 0	$ 0
Owners' equity:
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares issued (in shares)	56,422,449	42,532,353
Common stock, shares outstanding (in shares)	56,030,634	42,143,463
Preferred stock, par value (in dollar per share)	$ 0.001	$ 0.001
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)	411,815	388,890

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) [Abstract]
Revenues		$ 1,699.4	$ 2,000.6	$ 3,379.1		$ 4,295.3
Costs and expenses:
Product purchases		1,237	1,616.6	2,505.3		3,531.7
Operating expenses		136.9	106.6	248.2		210.9
Depreciation and amortization expenses		163.9	85.9	282.5		165.4
General and administrative expenses		49.2	41.6	91.7		79.5
Other operating (income) expense		0	(0.4)	0.6		(1)
Income from operations		112.4	150.3	250.8		308.8
Other income (expense):
Interest expense, net		(70.2)	(35.7)	(125.1)		(69.6)
Equity earnings (loss)		(1.5)	4.2	0.5	[1]	9.1
Loss on debt redemptions and amendments		(3.8)	0	(12.9)		0
Other		1.7	(0.1)	(23.5)		0
Income before income taxes		38.6	118.7	89.8		248.3
Income tax (expense) benefit:
Current		(2.4)	(16.6)	(11.6)		(40.5)
Deferred		(12.4)	1.1	(18.5)		2.4
Income tax expense total		(14.8)	(15.5)	(30.1)		(38.1)
Net income		23.8	103.2	59.7		210.2
Less: Net income attributable to noncontrolling interests		8.6	76.8	41.1		164.2
Net income attributable to common shareholders		$ 15.2	$ 26.4	$ 18.6		$ 46
Net income available per common share - basic (in dollars per share)		$ 0.27	$ 0.63	$ 0.37		$ 1.10
Net income available per common share - diluted (in dollars per share)		$ 0.27	$ 0.63	$ 0.36		$ 1.09
Weighted average shares outstanding - basic (in shares)		55.9	42	50.9		42
Weighted average shares outstanding - diluted (in shares)	[2]	56.1	42.1	51		42.1
[1]	Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015.
[2]	For the six months ended June 30, 2015, approximately 1,895 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Targa Resources Corp.
Net income attributable to common shareholders	$ 15.2	$ 26.4	$ 18.6	$ 46
Commodity hedging contracts:
Change in fair value, pre-tax	(1.1)	(0.8)	0.6	(2.4)
Change in fair value, related income tax	0.4	0.3	(0.2)	0.9
Change in fair value, after tax	(0.7)	(0.5)	0.4	(1.5)
Settlements reclassified to revenues, pre-tax	(1.8)	0.5	(2.7)	1.4
Settlements reclassified to revenues, related income tax	0.7	(0.2)	1	(0.5)
Settlements reclassified to revenues, after tax	(1.1)	0.3	(1.7)	0.9
Interest rate swaps:
Settlements reclassified to interest expense, net, pre-tax	0	0.1	0	0.3
Settlements reclassified to interest expense, net, related income tax	0	(0.1)	0	(0.1)
Settlements reclassified to interest expense, net, after tax	0	0	0	0.2
Other comprehensive income (loss) attributable to Targa Resources Corp., pre-tax	(2.9)	(0.2)	(2.1)	(0.7)
Other comprehensive income (loss) attributable to Targa Resources Corp., related income tax	1.1	0	0.8	0.3
Other comprehensive income (loss) attributable to Targa Resources Corp., after tax	(1.8)	(0.2)	(1.3)	(0.4)
Comprehensive income attributable to Targa Resources Corp.	13.4	26.2	17.3	45.6
Noncontrolling interests
Net income attributable to noncontrolling interests	8.6	76.8	41.1	164.2
Commodity hedging contracts:
Change in fair value, pre-tax	(7.6)	(6)	15.9	(16.2)
Change in fair value, related income tax	0	0	0	0
Change in fair value, after tax	(7.6)	(6)	15.9	(16.2)
Settlements reclassified to revenues, pre-tax	(14.5)	4	(21.7)	9.4
Settlements reclassified to revenues, related income tax	0	0	0	0
Settlements reclassified to revenues, after tax	(14.5)	4	(21.7)	9.4
Interest rate swaps:
Settlements reclassified to interest expense, net, pre-tax	0	1	0	2.1
Settlements reclassified to interest expense, net, related income tax	0	0	0	0
Settlements reclassified to interest expense, net, after tax	0	1	0	2.1
Other comprehensive income (loss) attributable to noncontrolling interests, pre-tax	(22.1)	(1)	(5.8)	(4.7)
Other comprehensive income (loss) attributable to noncontrolling interests, related income tax	0	0	0	0
Other comprehensive income (loss) attributable to noncontrolling interests, after tax	(22.1)	(1)	(5.8)	(4.7)
Comprehensive income (loss) attributable to noncontrolling interests	(13.5)	75.8	35.3	159.5
Total
Net income	23.8	103.2	59.7	210.2
Commodity hedging contracts:
Change in fair value, pre-tax	(8.7)	(6.8)	16.5	(18.6)
Change in fair value, related income tax	0.4	0.3	(0.2)	0.9
Change in fair value, after tax	(8.3)	(6.5)	16.3	(17.7)
Settlements reclassified to revenues, pre-tax	(16.3)	4.5	(24.4)	10.8
Settlements reclassified to revenues, related income tax	0.7	(0.2)	1	(0.5)
Settlements reclassified to revenues, after tax	(15.6)	4.3	(23.4)	10.3
Interest rate swap:
Settlements reclassified to interest expense, net, pre-tax	0	1.1	0	2.4
Settlements reclassified to interest expense, net, related income tax	0	(0.1)	0	(0.1)
Settlements reclassified to interest expense, net, after tax	0	1	0	2.3
Other comprehensive income (loss), pre-tax	(25)	(1.2)	(7.9)	(5.4)
Other comprehensive income (loss), related income tax	1.1	0	0.8	0.3
Other comprehensive income (loss), after tax	(23.9)	(1.2)	(7.1)	(5.1)
Total comprehensive income	$ (0.1)	$ 102	$ 52.6	$ 205.1

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - USD ($) shares in Thousands, $ in Millions	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Shares [Member]	Noncontrolling Interests [Member]	Total
Balance at Dec. 31, 2013	$ 0	$ 151.6	$ 20.5	$ (0.5)	$ (22.8)	$ 1,942.5	$ 2,091.3
Balance (in shares) at Dec. 31, 2013	42,162				367
Compensation on equity grants	$ 0	2.6	0	0	$ 0	4.9	7.5
Compensation on equity grants (in shares)	4				0
Accrual of distribution equivalent rights	$ 0	0	0	0	$ 0	(1.4)	(1.4)
Repurchase of common stock	$ 0	0	0	0	$ (0.8)	0	(0.8)
Repurchase of common stock (in shares)	(8)				8
Sale of Partnership limited partner interests	$ 0	0	0	0	$ 0	163	163
Impact of Partnership equity transactions	0	8.6	0	0	0	(8.6)	0
Dividends	0	0	(40)	0	0	0	(40)
Dividends in excess of retained earnings	0	(13)	0	0	0	0	(13)
Distributions to noncontrolling interests	0	0	0	0	0	(168.7)	(168.7)
Other comprehensive income (loss)	0	0	0	(0.4)	0	(4.7)	(5.1)
Net income	0	0	46	0	0	164.2	210.2
Balance at Jun. 30, 2014	$ 0	149.8	26.5	(0.9)	$ (23.6)	2,091.2	2,243
Balance (in shares) at Jun. 30, 2014	42,158				375
Balance at Dec. 31, 2014	$ 0	164.9	25.5	4.8	$ (25.4)	2,369.7	2,539.5
Balance (in shares) at Dec. 31, 2014	42,143				389
Compensation on equity grants	$ 0	3.5	0	0	$ 0	8.9	12.4
Compensation on equity grants (in shares)	0				0
Accrual of distribution equivalent rights	$ 0	(0.3)	0	0	$ 0	(0.7)	(1)
Shares issued under compensation program	$ 0	0	0	0	$ 0	0	0
Shares issued under compensation program (in shares)	47				0
Common stock and Partnership units tendered for tax withholding obligations	$ 0	0	0	0	$ (2.1)	(2.1)	(4.2)
Common stock and Partnership units tendered for tax withholding obligations (in shares)	(23)				23
Sale of Partnership limited partner interests	$ 0	0	0	0	$ 0	293.4	293.4
Proceeds from equity issuances	$ 0	336.6	0	0	$ 0	0	336.6
Proceeds from equity issuances (in shares)	3,738				0
Impact of Partnership equity transactions	$ 0	56.5	0	0	$ 0	(56.5)	0
Dividends	0	0	(28.7)	0	0	0	(28.7)
Dividends in excess of retained earnings	0	(50.2)	0	0	0	0	(50.2)
Distributions to noncontrolling interests	0	0	0	0	0	(226.9)	(226.9)
Contributions from noncontrolling interests	0	0	0	0		5.9	5.9
Noncontrolling interest in acquired subsidiaries	0	0	0	0	0	113.4	113.4
Common stock issued in ATLS merger	$ 0.1	1,013.6	0	0	$ 0	0	1,013.7
Common stock issued in ATLS merger (in shares)	10,126				0
Issuance of Partnership units in APL merger	$ 0	0	0	0	$ 0	2,435.7	2,435.7
Other comprehensive income (loss)	0	0	0	(1.3)	0	(5.8)	(7.1)
Net income	0	0	18.6	0	0	41.1	59.7
Balance at Jun. 30, 2015	$ 0.1	$ 1,524.6	$ 15.4	$ 3.5	$ (27.5)	$ 4,976.1	$ 6,492.2
Balance (in shares) at Jun. 30, 2015	56,031				412

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014
Cash flows from operating activities
Net income	$ 59.7		$ 210.2
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense	7.2		6.9
Compensation on equity grants	12.4		7.5
Depreciation and amortization expenses	282.5		165.4
Accretion of asset retirement obligations	2.7		2.2
Deferred income tax expense (benefit)	18.5		(2.4)
Equity earnings of unconsolidated affiliate	(0.5)	[1]	(9.1)
Distributions received from unconsolidated affiliates	6.9		9.1
Risk management activities	31.5		(0.7)
Gain on sale or disposition of assets	(0.2)		(1.2)
Loss on debt redemptions and amendments	12.9		0
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets	131.7		(31.7)
Inventory	57.9		(18.1)
Accounts payable and other liabilities	(139)		86.4
Net cash provided by operating activities	484.2		424.5
Cash flows from investing activities
Outlays for property, plant and equipment	(436.2)		(419.6)
Outlays for business acquisitions, net of cash acquired	(1,574.4)		0
Return of capital from unconsolidated affiliate	0.1		3.6
Other, net	(1.3)		2.3
Net cash used in investing activities	(2,011.8)		(413.7)
Partnership debt obligations:
Proceeds from borrowings under credit facilities	1,343		950
Repayments of credit facilities	(465)		(850)
Proceeds from accounts receivable securitization facility	253.4		67.8
Repayments of accounts receivable securitization facility	(312)		(113.2)
Proceeds from issuance of senior notes	1,100		0
Redemption of APL senior notes	(1,168.8)		0
Non-Partnership debt obligations:
Proceeds from borrowings under credit facility	481		39
Repayments of credit facility	(123)		(36)
Proceeds from issuance of senior term loan	422.5		0
Repayments on senior term loan	(270)		0
Costs incurred in connection with financing arrangements	(37.1)		(1.7)
Proceeds from sale of common units of the Partnership	295.8		164.7
Repurchase of common units under Partnership compensation plans	(2.1)		0
Contributions from noncontrolling interests	5.9		0
Distributions to noncontrolling interests	(226.9)		(168.7)
Proceeds from TRC equity offerings	336.6		0
Repurchase of common stock under TRC compensation plans	(2.1)		(0.8)
Dividends to common shareholders	(78.9)		(52.7)
Net cash provided by (used in) financing activities	1,552.3		(1.6)
Net change in cash and cash equivalents	24.7		9.2
Cash and cash equivalents, beginning of period	81		66.7
Cash and cash equivalents, end of period	$ 105.7		$ 75.9
[1]	Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015.

Organization

Organization	6 Months Ended
	Jun. 30, 2015
Organization [Abstract]
Organization	Note 1 — Organization Targa Resources Corp. (“TRC”) is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Quarterly 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	6 Months Ended
	Jun. 30, 2015
Basis of Presentation [Abstract]
Basis of Presentation	Note 2 Basis of Presentation We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report. The unaudited consolidated financial statements for the three and six months ended June 30, 2015 and 2014 include all adjustments that we believe are necessary for a fair presentation of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. Our financial results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the full year. One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership” or “TRP”). 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 consolidated results of operations as net income attributable to noncontrolling interests and in our consolidated 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 June 30, 2015, 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”); · 16,309,594 common units of the Partnership, representing an 8.9% limited partnership interest; and · a Special GP Interest representing retained tax benefits related to the contribution to the Partnership from us of the APL general partner interest acquired in the ATLS merger (see Note 4 – Business Acquisitions). 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 18 – Segment Information 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 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.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Significant Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the six months ended June 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers. Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. The Partnership evaluates goodwill for impairment at least annually, as of November 30 th Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory

Business Acquisitions

Business Acquisitions	6 Months Ended
	Jun. 30, 2015
Business Acquisitions [Abstract]
Business Acquisitions	Note 4 – Business Acquisitions 2015 Acquisition Atlas Mergers On February 27, 2015, (i) Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, APL and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While these were two separate legal transactions involving different groups of unitholders, for GAAP reporting purposes these two mergers are viewed as a single integrated transaction. In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.” In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”). On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of a special general partner interest in the Partnership (the “Special GP Interest”) representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL The Partnership acquired all $5.3 billion Pursuant to the APL Merger Agreement, Targa agreed to cause the general partner of the Partnership to enter into an amendment to the Partnership’s partnership agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to us, as the holder of the Partnership’s IDRs, by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of the Partnership’s outstanding common units. TPL 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 Atlas mergers add TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of the Partnership’s common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. The Partnership issued 58,614,157 of its common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, we contributed $52.4 million to the Partnership to maintain our 2% general partner interest. In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger. The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). We issued 10,126,532 of our common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date. ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Our acquisition of ATLS resulted in our acquiring these common units (converted to 3,363,935 Partnership common units) valued at approximately $147.4 million (based on the $43.82 closing market price of a Partnership common unit on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million. All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of the Company in connection with the Atlas Transactions (the “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of the Partnership’s common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award. Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations The acquired business contributed revenues of $616.8 million and net income of $17.8 million to the Company for the period from February 27, 2015 to June 30, 2015, and is reported in our Field Gathering and Processing segment. In 2015, we incurred $26.6 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statement of Operations for the six months ended June 30, 2015. The following summarized unaudited pro forma consolidated statement of operations information for the six months ended June 30, 2015 and June 30, 2014 assumes that the Partnership’s acquisition of APL and our acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed this acquisition as of January 1, 2014, or that the results that will be attained in the future. Pro Forma Results for the Six Months Ended June 30, 2015 June 30, 2014 Revenues $ 3,667.8 $ 5,647.6 Net income 41.7 182.0 The pro forma consolidated results of operations amounts have been calculated after applying the Company’s accounting policies, and making adjustments to: · Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and our preliminary estimate of the fair value of intangible assets acquired. · Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and our preliminary estimate of the fair value of property, plant and equipment acquired. · Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense. · Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger. · Remove the results of operations attributable to APL businesses sold during the periods: (1) the May 2014 sale of APL’s 20% interest in West Texas LPG Pipeline Limited Partnership and (2) the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee. · Exclude $26.6 million of acquisition-related costs incurred in 2015 from pro forma net income for the six months ended June 30, 2015. Pro forma net income for the six months ended June 30, 2014 was adjusted to include these charges. · To conform to our accounting policy, we also adjusted TPL’s revenues to report plant sales of Y-grade at contractual net-back values, rather than grossed up for transportation and fractionation deduction factors. The following table summarizes the consideration transferred to acquire ATLS and APL: Fair Value of Consideration Transferred: Cash paid, net of cash acquired (1): TRC $ 745.7 TRP 828.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (2) 5.2 Common units of TRP 2,421.1 Replacement phantom units awarded (2) 15.0 Total $ 5,024.2 (1) Net of cash acquired of $40.8 million, including $7.3 million received in April 2015 by us as part of the Atlas mergers, representing the one-time cash payment from the Partnership for the APL common units owned by ATLS. The one-time cash payment was paid by the Partnership in February 2015 and received by us from the transfer agent in April 2015. (2) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $557.9 million, which was recorded as goodwill. Preliminary fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 25.1 Assets from risk management activities 102.1 Property, plant and equipment 4,693.2 Investments in unconsolidated affiliates 214.2 Intangible assets 1,204.0 Other long-term assets 6.6 Current liabilities (255.6 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (8.6 ) Other long-term liabilities (9.1 ) Total identifiable net assets 4,579.7 Noncontrolling interest in subsidiaries (113.4 ) Goodwill 557.9 $ 5,024.2 Our valuation of the acquired assets and liabilities is ongoing and may result in future measurement period adjustments to these preliminary fair values. The fair values of property, plant and equipment, investments in unconsolidated affiliates, intangible assets representing the GP interest, IDRs, customer contracts and customer relationships, deferred income taxes related to APL Arkoma, Inc., a taxable subsidiary acquired, and noncontrolling interest, which is calculated as a proportionate share of the fair value of the acquired joint ventures’ net assets, are preliminary pending completion of final valuations. As a result, goodwill is also preliminary, as it has been recorded as the excess of the purchase price over the estimated fair value of net assets acquired. During the three months ended June 30, 2015, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the statement of operations for the three months ended March 31, 2015 has been retrospectively adjusted for the impact of measurement period adjustments to property, plant and equipment, intangible assets, and investment in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the three months ended March 31, 2015. The preliminary valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. The preliminary determination of goodwill of $557.9 million is attributable to the workforce of the acquired business and the expected synergies with us and the Partnership. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination. The fair value of assets acquired includes trade receivables of $178.1 million. The gross amount due under contracts is $178.1 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty. See Note 10 - Debt Obligations for additional disclosures regarding related financing activities associated with the Atlas mergers. Contingent Consideration A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in a decrease in the acquisition date fair value from $6.0 million to $4.2 million. Any future change in the fair value of this liability will be included in earnings. Replacement Restricted Stock Units (“RSUs”) In connection with the ATLS merger, we awarded RSUs in accordance with and as required by the Atlas Merger Agreements to those APL employees that who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing ATLS awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 25% after the third year of the original term and 75% after the fourth year of the original term. Each will entitle the grantee to one common share on the vesting date and is an equity-settled award. The include dividend equivalents. The fair value of the was based on the closing price of our common shares at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and future compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. Replacement Phantom Units In connection with the APL merger, the Partnership awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term. Each replacement phantom unit will entitle the grantee to one common unit on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). The fair value of the replacement phantom units was based on the closing price of the Partnership’s units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and future compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

Inventories

Inventories	6 Months Ended
	Jun. 30, 2015
Inventories [Abstract]
Inventories	Note 5 — Inventories June 30, 2015 December 31, 2014 Partnership: Commodities $ 112.7 $ 157.4 Materials and supplies 12.1 11.5 $ 124.8 $ 168.9

Property, Plant and Equipment a

Property, Plant and Equipment and Intangible Assets	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment and Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	Note 6 — Property, Plant and Equipment and Intangible Assets June 30, 2015 December 31, 2014 Estimated Useful Lives (In Years) Gathering systems $ 6,052.6 $ 2,588.6 5 to 40 Processing and fractionation facilities 2,982.6 1,890.7 5 to 40 Terminaling and storage facilities 1,090.0 1,038.9 5 to 25 Transportation assets 438.7 359.0 10 to 25 Other property, plant and equipment 210.0 149.3 3 to 40 Land 102.7 95.6 - Construction in progress 725.4 399.0 - Property, plant and equipment 11,602.0 6,521.1 Accumulated depreciation (1,917.7 ) (1,696.5 ) Property, plant and equipment, net $ 9,684.3 $ 4,824.6 Intangible assets $ 1,885.6 $ 681.8 20 Accumulated amortization (150.0 ) (89.9 ) Intangible assets, net $ 1,735.6 $ 591.9 Intangible assets consist of customer contracts and customer relationships acquired in our Atlas mergers and our Badlands business acquisitions. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values 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. The fair values of intangible assets acquired in the Atlas mergers have been recorded at a preliminary value of $1,204.0 million pending completion of final valuations. For the purpose of our preparing the accompanying financial statements (which includes four months of amortization of these intangible assets), we have amortized these intangible assets over a 20 year life using a straight-line method. The amortization method and lives for the Atlas mergers intangible assets will be reviewed and possibly revised as we finalize the valuations over the upcoming months. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation. The estimated annual amortization expense for intangible assets, including the preliminary Atlas valuation and straight-line treatment is approximately $130.1 million, $148.3 million, $141.5 million, $127.8 million and $116.8 million for each of the years 2015 through 2019.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
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 ARO are as follows: Six Months Ended June 30, 2015 Beginning of period $ 57.1 Preliminary fair value of ARO acquired with APL merger 4.0 Change in cash flow estimate 3.8 Accretion expense 2.7 End of period $ 67.6

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2015
Investment in Unconsolidated Affiliate [Abstract]
Investment in Unconsolidated Affiliate	Note 8 – Investment in Unconsolidated Affiliates The Partnership’s unconsolidated investment consisted of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and . The following table shows the activity related to the Partnership’s investments in unconsolidated affiliates: Six Months Ended June 30, 2015 Beginning of period $ 50.2 Preliminary fair value of T2 Joint Ventures acquired 214.2 Equity earnings (1) 0.5 Cash distributions (2) (7.0 ) Cash calls for expansion projects 0.1 End of period $ 258.0 (1) Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015. (2) Includes $0.1 million distributions received in excess of the Partnership’s share of cumulative earnings for the six months ended June 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. The Partnership’s recorded value of the T2 Joint Ventures investment is based on preliminary fair values at the date of acquisition which results in an excess fair value of $39.6 million over the book value of our partner capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the preliminary estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 - Business Acquisitions for further information regarding the preliminary fair value determinations related to the Atlas mergers.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	6 Months Ended
	Jun. 30, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 — June 30, 2015 December 31, 2014 Targa Resources Partners LP TRC Non- Partnership Targa Resources Corp. Consolidated Targa Resources Partners LP TRC Non- Partnership Targa Resources Corp. Consolidated Commodities $ 402.5 $ - $ 402.5 $ 416.7 $ - $ 416.7 Other goods and services 105.9 1.4 107.3 108.9 2.2 111.1 Interest 63.3 1.0 64.3 37.3 - 37.3 Compensation and benefits 1.8 29.3 31.1 1.3 44.8 46.1 Income and other taxes 31.6 0.1 31.7 13.6 (1.9 ) 11.7 Other 47.6 4.6 52.2 14.9 0.7 15.6 $ 652.7 $ 36.4 $ 689.1 $ 592.7 $ 45.8 $ 638.5

Debt Obligations

Debt Obligations	6 Months Ended
	Jun. 30, 2015
Debt Obligations [Abstract]
Debt Obligations	Note 10 — Debt Obligations June 30, 2015 December 31, 2014 Current: Obligations of the Partnership Accounts receivable securitization facility, due December 2015 (1) $ 124.2 $ 182.8 Long-term: Non-Partnership obligations: TRC Senior secured revolving credit facility, variable rate, due February 2020 (2) 460.0 - TRC Senior secured term loan, variable rate, due February 2022 160.0 - Unamortized discount (2.7 ) - TRC Senior secured revolving credit facility, variable rate, due October 2017 - 102.0 Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due October 2017 (3) 878.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 6 ⅞ 483.6 483.6 Unamortized discount (23.8 ) (25.2 ) Senior unsecured notes, 6 ⅝ 342.1 - Unamortized premium 5.4 - Senior unsecured notes, 6 ⅜ 300.0 300.0 Senior unsecured notes, 5 ¼ 600.0 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 625.0 625.0 Senior unsecured notes, 4 ⅛ 800.0 800.0 Senior unsecured notes, 6 ⅝ 13.1 - Unamortized premium 0.2 - Senior unsecured notes, 4¾% fixed rate, due November 2021 (5) 6.5 - Senior unsecured notes, 5⅞% fixed rate, due August 2023 (5) 48.1 - Unamortized premium 0.6 - Total long-term debt 5,796.1 2,885.4 Total debt $ 5,920.3 $ 3,068.2 Irrevocable standby letters of credit: Letters of credit outstanding under the TRC Senior secured credit facility (2) $ - $ - Letters of credit outstanding under the Partnership senior secured revolving credit facility (3) 20.5 44.1 $ 20.5 $ 44.1 (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) As of , availability under TRC’s $670.0 million senior secured revolving credit facility was $210.0 million. (3) As of , availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $701.5 million. (4) In May 2015, the Partnership exchanged TRP 6⅝% Senior Notes with the same economic terms to holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us. (5) Senior unsecured notes issued by APL entities and acquired in the ATLS mergers. While the Partnership consolidates the debt acquired in the Atlas mergers, neither we nor the Partnership guarantees the acquired debt of APL. The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the six months ended June 30, 2015: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRC senior secured revolving credit facility 2.9% 2.9% TRC senior secured term loan 5.75% 5.75% Partnership's senior secured revolving credit facility 1.9% - 4.3% 2.0% Partnership's accounts receivable securitization facility 0.9% 0.9% Compliance with Debt Covenants As of June 30, 2015, both the Partnership and we were in compliance with the covenants contained in our various debt agreements. Partnership Financing Activities Revolving Credit Agreement In February 2015, the Partnership entered into the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amended its Second Amended and Restated Credit Agreement (the “Original Agreement”). The First Amendment increased available commitments to $1.6 billion from $1.2 billion while retaining the Partnership’s ability to request up to an additional $300.0 million in commitment increases. In addition, the First Amendment amends certain provisions of the Original Agreement to designate each of APL and its subsidiaries as an “Unrestricted Subsidiary.” The Partnership used proceeds from borrowings under the credit facility to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments. Senior Unsecured Notes In January 2015, the Partnership issued $1.1 billion in aggregate principal amount of 5% Senior Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,089.8 million of net proceeds, which were used with borrowings under the TRP Revolver to fund the APL Notes Tender Offers April 2015 Shelf In April 2015, the Partnership filed with the SEC a universal shelf registration statement that allows it to issue up to an aggregate of $1.0 billion of debt or equity securities (the "April 2015 Shelf"). The April 2015 Shelf expires in April 2018. Merger Financing Activities ATLS Merger Financing Activities In connection with the closing of the Atlas mergers, we entered into a Credit Agreement (the “TRC Credit Agreement”), dated as of February 27, 2015, among us, each lender from time to time party thereto and Bank of America, N.A. as administrative agent, collateral agent, swing line lender and letter of credit issuer. The TRC Credit Agreement provides for a new five year revolving credit facility in an aggregate principal amount up to $670 million and a seven year variable rate term loan facility in an aggregate principal amount of $430 million. This facility was issued at a 1.75% discount. The outstanding term loans are Eurodollar rate loans with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of 4.75%. We used the net proceeds from the term loan issuance and the revolving credit facility to fund cash components of the ATLS merger, including cash merger consideration and approximately $160.2 million related to change of control payments made by ATLS, cash settlements of equity awards and transaction fees and expenses. In March 2015, we repaid $188.0 million of the term loan and wrote off $3.3 million of the discount and $5.7 million of debt issuance costs. In June 2015, we repaid $82.0 million of the term loan and wrote off $1.4 million of the discount and $2.4 million of debt issuance costs. The write-off of the discounts and debt issuance costs are reflected as loss on debt redemptions and amendments on the Consolidated Statements of Operations for the three and six months ended June 30, 2015. APL Senior Notes Tender Offers In January 2015, the Partnership commenced cash tender offers for any and all of the outstanding fixed rate senior secured notes to be acquired in the APL merger, referred to as the APL Notes Tender Offers, which totaled $1.55 billion. The results of the APL Notes Tender Offers were: Senior Notes Outstanding Note Balance Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer payments % Tendered Note Balance after Tender Offers ($ amounts in millions) 6⅝% due 2020 $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% due 2021 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% due 2023 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5 In connection with the APL Notes Tender Offers, on February 27, 2015, the supplemental indentures governing the 4¾% Senior Notes due 2021 (the “2021 APL Notes”) and the 5⅞% Senior Notes due 2023 (the “2023 APL Notes”) of TPL and Targa Pipeline Finance Corporation (formerly known as Atlas Pipeline Finance Corporation) (together, the “APL Issuers”), became operative. These supplemental indentures eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2021 APL Notes and the 2023 APL Notes that were not accepted for payment. Not having achieved the minimum tender condition on the 6⅝% Senior Notes due 2020 of the APL Issuers (the “2020 APL Notes”), the Partnership made a change of control offer, referred to as the Change of Control Offer, for any and all of the 2020 APL Notes in advance of, and conditioned upon, the consummation of the APL merger. In March 2015, holders representing $4.8 million of the outstanding 2020 APL Notes tendered their notes requiring a payment of $5.0 million, which included the change of control premium and accrued interest. Payments made under the APL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities in the Consolidated Statements of Cash Flows. Exchange Offer and Consent Solicitation On April 13, 2015, the Partnership and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) commenced an offer to exchange (the “Exchange Offer”) for any and all of the outstanding 2020 APL Notes for an equal amount of new unsecured 6⅝% Senior Notes due 2020 issued by the Partnership Issuers (the “6⅝% Notes” or the “TRP 6⅝% Notes”). On April 27, 2015, the Partnership had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 APL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes. In May 2015, upon the closing of the Exchange Offer, the Partnership issued $342.1 million aggregate principal amount of the TRP 6⅝% Notes to holders of the 2020 APL Notes which were validly tendered for exchange. The related $5.6 million premium, resulted from acquisition date fair value accounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6⅝% Notes.

Partnership Units and Related M

Partnership Units and Related Matters	6 Months Ended
	Jun. 30, 2015
Partnership Units and Related Matters [Abstract]
Partnership Units and Related Matters	Note 11 — Partnership Units and Related Matters Issuances of Common Units As part of the Atlas APL ATLS’s APL, which In May 2014, the Partnership entered into an additional Equity Distribution Agreement under the July 2013 Shelf (the “May 2014 EDA”), pursuant to which it may sell through its sales agents, at its option, up to an aggregate of $400.0 million of its common units. During the six months ended June 30, 2015, the Partnership issued 3,590,826 common units under the May 2014 EDA, receiving total net proceeds of $153.0 million (net of commissions up to 1% of gross proceeds to its sales agents). We contributed $3.1 million to the Partnership to maintain our 2% general partner interest. In May 2015, the Partnership entered into an additional Equity Distribution Agreement under a shelf registration statement filed in April 2015 (the “May 2015 EDA”), pursuant to which the Partnership may sell through its sales agents, at its option, up to an aggregate of $1.0 billion of the Partnership’s common units. During the six months ended June 30, 2015, the Partnership issued 3,222,981 common units under the May 2015 EDA, receiving total net proceeds of $140.5 million (net of commissions up to 0.75% of gross proceeds to its sales agents). We contributed $2.9 million to maintain our 2% general partner interest, of which $0.9 million was received by the Partnership in July 2015. Subsequent Event During July 2015, the Partnership issued 563,573 common units under the May 2015 EDA, receiving net proceeds of $22.6 million. We contributed $0.5 million to the Partnership to maintain our 2% general partner interest. As of July 31, 2015, approximately $835.6 million of the aggregate offering amount remained available for sale pursuant to the May 2015 EDA. Distributions In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as defined in the Partnership Agreement, and as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. 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) June 30, 2015 August 14, 2015 $ 152.5 $ 43.9 (1 ) $ 4.0 $ 200.4 $ 61.4 $ 0.8250 March 31, 2015 May 15, 2015 148.3 41.7 (1 ) 3.9 193.9 59.0 0.8200 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 51.6 0.8100 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

Common Stock and Related Matter

Common Stock and Related Matters	6 Months Ended
	Jun. 30, 2015
Common Stock and Related Matters [Abstract]
Common Stock and Related Matters	Note 12 — Common Stock and Related Matters On February 27, 2015, we issued 10,126,532 shares of our common stock valued at approximately $1.0 billion in exchange for ATLS common units as part of the ATLS merger (based on the $99.58 closing market price of our common shares on the NYSE as of February 27, 2015). In addition, we awarded 81,740 RSUs in connection with the ATLS mergers. Public Offering During March 2015, we sold, in a public offering, 3,250,000 shares of our common stock under a registration statement on Form S-3 at a price of $91 per share of common stock, providing net proceeds of $292.8 million to us. Pursuant to the exercise of the underwriters’ overallotment option, we also sold an additional 487,500 shares of our common stock, providing additional net proceeds of $43.9 million. The proceeds from this offering were used to repay a portion of the outstanding borrowings under our term loan and to make a capital contribution of $52.4 million to the Partnership to maintain our 2% general partnership interest in the Partnership and for general corporate purposes. Dividends The following table details the dividends declared and/or paid 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) June 30, 2015 August 17, 2015 $ 49.2 $ 49.0 $ 0.2 $ 0.87500 March 31, 2015 May 18, 2015 46.6 46.4 0.2 0.83000 December 31, 2014 February 17, 2015 32.8 32.6 0.2 0.77500 (1) Represents accrued dividends on 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	6 Months Ended
	Jun. 30, 2015
Earnings per Common Share [Abstract]
Earnings per Common Share	Note 13 — Earnings 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: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income $ 23.8 $ 103.2 $ 59.7 $ 210.2 Less: Net income attributable to noncontrolling interests 8.6 76.8 41.1 164.2 Net income attributable to common shareholders $ 15.2 $ 26.4 $ 18.6 $ 46.0 Weighted average shares outstanding - basic 55.9 42.0 50.9 42.0 Net income available per common share - basic $ 0.27 $ 0.63 $ 0.37 $ 1.10 Weighted average shares outstanding 55.9 42.0 50.9 42.0 Dilutive effect of unvested stock awards 0.2 0.1 0.1 0.1 Weighted average shares outstanding - diluted (1) 56.1 42.1 51.0 42.1 Net income available per common share - diluted $ 0.27 $ 0.63 $ 0.36 $ 1.09 (1) For the six months ended June 30, 2015, approximately 1,895 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2015
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 delivery points of the Partnership’s physical equity volumes. The Partnership’s natural gas hedges are a mixture of specific gas delivery points and Henry Hub. 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. 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. As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to the Partnership and included in the acquisition date fair value of assets acquired. Derivative settlements of $23.1 million and $31.5 million related to these novated contracts were received during the three and six months ended June 30, 2015 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired with no effect on results of operations. The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Certain novated APL crude options with a fair value of $7.7 million as of the acquisition date did not fall within the “highly effective” correlation range required to qualify as a hedging instrument for accounting purposes. These non-qualifying hedges resulted in $1.3 million and $0.2 million Additionally, for the three and six months ended June 30, 2015, At June 30, 2015, the notional volumes of the Partnership’s commodity derivative contracts were: Commodity Instrument Unit 2015 2016 2017 2018 Natural Gas Swaps MMBtu/d 134,141 68,205 23,082 - Natural Gas Basis Swaps MMBtu/d 55,734 18,853 9,041 - Natural Gas Collars MMBtu/d - 7,500 7,500 1,849 NGL Swaps Bbl/d 5,015 2,254 658 - NGL Options/Collars Bbl/d 1,083 920 920 32 Condensate Swaps Bbl/d 1,826 1,082 500 - Condensate Options/Collars Bbl/d 1,605 790 790 101 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 permit its contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. 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 June 30, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 87.3 $ 1.9 $ 44.4 $ - Long-term 40.3 5.3 15.8 - Total derivatives designated as hedging instruments $ 127.6 $ 7.2 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 4.5 $ - $ - $ 5.2 Total derivatives not designated as hedging instruments $ 4.5 $ - $ - $ 5.2 Total current position $ 91.8 $ 1.9 $ 44.4 $ 5.2 Total long-term position 40.3 5.3 15.8 - Total derivatives $ 132.1 $ 7.2 $ 60.2 $ 5.2 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 June 30, 2015 Asset Position Liability Position Asset Position Liability Position Current position Counterparties with offsetting position $ 77.2 $ 1.9 $ 75.3 $ - Counterparties without offsetting position - assets 14.6 - 14.6 - Counterparties without offsetting position - liabilities - - - - 91.8 1.9 89.9 - Long-term position Counterparties with offsetting position 33.8 5.3 28.5 - Counterparties without offsetting position - assets 6.5 - 6.5 - Counterparties without offsetting position - liabilities - - - - 40.3 5.3 35.0 - Total derivatives Counterparties with offsetting position 111.0 7.2 103.8 - Counterparties without offsetting position - assets 21.1 - 21.1 - Counterparties without offsetting position - liabilities - - - - $ 132.1 $ 7.2 $ 124.9 $ - December 31, 2014 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 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 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 $124.9 million as of June 30, 2015. 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 Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Hedging Relationships Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts $ (8.7 ) $ (6.8 ) $ 16.5 $ (18.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Interest expense, net $ - $ (1.1 ) $ - $ (2.4 ) Revenues 16.3 (4.5 ) 24.4 (10.8 ) $ 16.3 $ (5.6 ) $ 24.4 $ (13.2 ) 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 Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts Revenue $ (4.0 ) $ (0.1 ) $ 3.2 $ (0.3 ) 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 2018 based on year-end valuations: June 30, 2015 December 31, 2014 Commodity hedges, before tax (1) $ 52.4 $ 60.3 (1) Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months. See Note 15 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
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 and contingent consideration related to business acquisitions 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 present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying 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 June 30, 2015, a net asset position of $124.9 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 $92.5 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 $154.6 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: • Our and the Partnership’s senior secured revolving credit facilities and the Partnership’s accounts receivable securitization facility (“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: June 30, 2015 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) $ 132.1 $ 132.1 $ - $ 129.0 $ 3.1 Liabilities from commodity derivative contracts (1) 7.2 7.2 - 4.8 2.4 TPL contingent consideration (2) 4.2 4.2 - - 4.2 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 105.7 105.7 - - - TRC Senior secured revolving credit facility 460.0 460.0 - 460.0 - TRC Term Loan 157.3 167.6 - 167.6 - Partnership's Senior secured revolving credit facility 878.0 878.0 - 878.0 - Partnership's Senior unsecured notes 4,300.8 4,360.8 - 4,360.8 - Partnership's accounts receivable securitization facility 124.2 124.2 - 124.2 - (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 - Derivative Instruments and Hedging Activities. 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. (2) See Note 4 – Business Acquisitions. Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets We reported certain of the Partnership’s swaps and option contracts 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 June 30, 2015, the Partnership had 29 commodity swap and option contracts 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. T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2014 $ (1.7 ) $ - TPL contingent consideration (Note 4 - Business Acquisitions) - 4.2 New Level 3 instruments (0.7 ) - Transfers out of Level 3 1.7 - Balance, June 30, 2015 $ (0.7 ) $ 4.2 For the six months ended June 30, 2015, the Partnership transferred $1.7 million in derivative liabilities out of Level 3 and into Level 2. These transfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2015
Contingencies [Abstract]
Contingencies	Note 16 – Contingencies Legal Proceedings Targa Shareholder Litigation On January 28, 2015, a public shareholder of Targa (the “TRC Plaintiff”) filed a putative class action and derivative lawsuit against Targa (as a nominal defendant), its directors at the time of the ATLS merger (the “TRC Director Defendants”), and ATLS (together with Targa and the TRC Director Defendants, the “TRC Lawsuit Defendants”). This lawsuit was styled Inspired Investors v. Joe Bob Perkins, et al. The TRC Plaintiff alleged a variety of causes of action challenging the ATLS merger and the disclosures related to the ATLS merger. Generally, the TRC Plaintiff alleged that the TRC Director Defendants breached their fiduciary duties. The TRC Plaintiff further alleged that the registration statement filed on January 22, 2015 failed 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) Targa’s financial projections, (iii) the background of the ATLS merger, and (iv) Wells Fargo Securities, LLC’s analysis of the ATLS merger. The TRC Plaintiff also alleged that Targa overpaid to acquire ATLS. Based on these allegations, the TRC Plaintiff sought to enjoin the TRC Lawsuit Defendants from proceeding with or consummating the ATLS merger. The TRC Plaintiff also sought rescission, damages, and attorneys’ fees. On February 25, 2015, the Harris County trial court denied the TRC Plaintiff’s request for a preliminary injunction. The ATLS merger occurred on February 27, 2015. The TRC Plaintiff voluntarily filed a joint motion to dismiss the TRC Lawsuit on June 4, 2015. The Harris County trial court dismissed the TRC Lawsuit with prejudice on June 9, 2015. Atlas Unitholder Litigation Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, APL GP, its managers, Targa, the Partnership, the general partner and MLP Merger Sub (the “APL Lawsuit Defendants”). These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Evnin, Greenthal, Welborn and Feldbaum In re Atlas Pipeline Partners, L.P. Unitholder Litigation Rick Kane v. Atlas Energy, L.P., et al. Jeffrey Ayers v. Atlas Energy, L.P., et al. In re Atlas Energy, L.P. Unitholder Litigation Kane The Atlas Lawsuit Plaintiffs alleged a variety of causes of action challenging the Atlas mergers. Generally, the APL Plaintiffs alleged that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, the Partnership, the general partner, MLP Merger Sub, 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 alleged that (a) the premium offered to APL’s unitholders was inadequate, (b) APL agreed to contractual terms that would 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 alleged that the registration statement filed on November 19, 2014 failed, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the Atlas mergers; (ii) APL and the Partnership’s financial projections; and (iii) the background of the Atlas mergers. Generally, the ATLS Plaintiffs alleged that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, GP Merger Sub, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further alleged that (a) the premium offered to the ATLS unitholders was inadequate, (b) ATLS agreed to contractual terms that would 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 failed 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 Atlas mergers; (ii) the Partnership, Targa, APL, and ATLS’ financial projections; and (iii) the background of the Atlas mergers. 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. The Atlas Lawsuit Plaintiffs also sought rescission, damages, and 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 would 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 finalizing settlement agreements and expect to seek court approval of the settlements. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 17 - Supplemental Cash Flow Information Six Months Ended June 30, 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 101.3 $ 62.7 Income taxes paid, net of refunds 13.2 35.9 Non-cash Investing and Financing balance sheet movements: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements 0.3 0.3 Deadstock commodity inventories transferred to property, plant and equipment 0.5 15.9 Impact of capital expenditure accruals on property, plant and equipment (52.9 ) (30.1 ) Transfers from materials and supplies inventory to property, plant and equipment 1.6 1.4 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) Non-cash merger consideration - common units and replacement equity awards $ 2,436.1 $ - Non-cash merger consideration - common shares and replacement equity awards 1,013.7 - Net non-cash balance sheet movements excluded from consolidated statements of cash flows 3,449.8 - Net cash merger consideration included in investing activities 1,574.4 - Total fair value of consideration transferred $ 5,024.2 $ - (1) Interest capitalized on major projects was $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Information [Abstract]
Segment Information	Note 18 — 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 operating margin results of its commodity derivative activities 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 the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; and the Williston Basin 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 (including any hedge ineffectiveness) We are reviewing our segment disclosures as a result of both the merger and integration efforts related to the Atlas mergers. Reportable segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities: Three Months Ended June 30, 2015 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Consolidated Revenues Sales of commodities $ 434.1 $ 52.6 $ 30.8 $ 861.5 $ 17.1 $ - $ 1,396.1 $ - $ 1,396.1 Fees from midstream services 106.2 7.4 89.6 100.1 - - 303.3 - 303.3 540.3 60.0 120.4 961.6 17.1 - 1,699.4 - 1,699.4 Intersegment revenues Sales of commodities 212.8 57.7 2.0 68.6 - (341.1 ) - - - Fees from midstream services 1.9 - 63.1 5.4 - (70.4 ) - - - 214.7 57.7 65.1 74.0 - (411.5 ) - - - Revenues $ 755.0 $ 117.7 $ 185.5 $ 1,035.6 $ 17.1 $ (411.5 ) $ 1,699.4 $ - $ 1,699.4 Operating margin $ 138.2 $ 6.5 $ 112.7 $ 51.0 $ 17.1 $ - $ 325.5 $ - $ 325.5 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 $ 115.3 $ 13,352.9 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 $ - $ 557.9 Capital expenditures $ 142.7 $ 4.8 $ 74.4 $ 5.9 $ - $ 1.3 $ 229.1 $ - $ 229.1 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations. (2) Total assets include goodwill. Three Months Ended June 30, 2014 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Consolidated Revenues Sales of commodities $ 62.9 $ 89.7 $ 28.9 $ 1,581.7 $ (4.0 ) $ - 1,759.2 $ - $ 1,759.2 Fees from midstream services 43.1 10.5 72.7 115.1 - - 241.4 - 241.4 106.0 100.2 101.6 1,696.8 (4.0 ) - 2,000.6 - 2,000.6 Intersegment revenues Sales of commodities 381.9 163.4 0.8 137.0 - (683.1 ) - - - Fees from midstream services 1.1 - 72.3 7.6 - (81.0 ) - - - 383.0 163.4 73.1 144.6 - (764.1 ) - - - Revenues $ 489.0 $ 263.6 $ 174.7 $ 1,841.4 $ (4.0 ) $ (764.1 ) 2,000.6 $ - $ 2,000.6 Operating margin $ 97.7 $ 21.8 $ 108.6 $ 53.3 $ (4.0 ) $ - 277.4 $ - $ 277.4 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 6,240.0 $ 88.4 $ 6,328.4 Capital expenditures $ 128.4 $ 3.1 $ 67.5 $ 15.5 $ - $ 1.0 215.5 $ - $ 215.5 Six Months Ended June 30, 2015 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Total Revenues Sales of commodities $ 602.0 $ 105.3 $ 58.1 $ 1,994.1 $ 38.8 $ - $ 2,798.3 $ - $ 2,798.3 Fees from midstream services 169.5 16.1 177.4 217.8 - - 580.8 - 580.8 771.5 121.4 235.5 2,211.9 38.8 - 3,379.1 - 3,379.1 Intersegment revenues - Sales of commodities 428.2 120.4 3.2 147.1 - (698.9 ) - - - Fees from midstream services 3.8 - 135.6 9.9 - (149.3 ) - - - 432.0 120.4 138.8 157.0 - (848.2 ) - - - Revenues $ 1,203.5 $ 241.8 $ 374.3 $ 2,368.9 $ 38.8 $ (848.2 ) $ 3,379.1 $ - $ 3,379.1 Operating margin $ 217.3 $ 14.1 $ 238.1 $ 117.3 $ 38.8 $ - $ 625.6 $ - $ 625.6 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 $ 115.3 $ 13,352.9 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 $ - $ 557.9 Capital expenditures $ 235.6 $ 6.0 $ 132.1 $ 8.9 $ - $ 2.3 $ 384.9 $ - $ 384.9 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations. (2) Total assets include goodwill. Six Months Ended June 30, 2014 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Total Sales of commodities $ 108.7 $ 190.2 $ 49.9 $ 3,505.4 $ (10.1 ) $ - $ 3,844.1 $ - $ 3,844.1 Fees from midstream services 83.9 18.2 140.8 208.3 - - 451.2 - 451.2 192.6 208.4 190.7 3,713.7 (10.1 ) - 4,295.3 - 4,295.3 Intersegment revenues Sales of commodities 782.2 340.4 1.4 267.5 - (1,391.5 ) - - - Fees from midstream services 2.1 - 138.6 15.4 - (156.1 ) - - - 784.3 340.4 140.0 282.9 - (1,547.6 ) - - - Revenues $ 976.9 $ 548.8 $ 330.7 $ 3,996.6 $ (10.1 ) $ (1,547.6 ) $ 4,295.3 $ - $ 4,295.3 Operating margin $ 191.7 $ 47.8 $ 205.4 $ 117.9 $ (10.1 ) $ - $ 552.7 $ - $ 552.7 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 $ 88.4 $ 6,328.4 Capital expenditures $ 227.3 $ 7.4 $ 136.1 $ 18.6 $ - $ 1.5 $ 390.9 $ - $ 390.9 Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Sales of commodities: Natural gas $ 443.5 $ 358.1 $ 750.9 $ 750.4 NGL 854.1 1,335.5 1,884.6 2,986.4 Condensate 51.3 41.8 72.8 70.1 Petroleum products 30.1 28.2 56.5 48.3 Derivative activities 17.1 (4.4 ) 33.5 (11.1 ) 1,396.1 1,759.2 2,798.3 3,844.1 Fees from midstream services: Fractionating and treating 54.7 51.7 104.5 98.2 Storage, terminaling, transportation and export 121.6 125.9 257.7 227.1 Gathering and processing 105.7 48.0 174.1 90.6 Other 21.3 15.8 44.5 35.3 303.3 241.4 580.8 451.2 Total revenues $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3 The following table shows a reconciliation of operating margin to net income for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Reconciliation of operating margin to net income: Operating margin $ 325.5 $ 277.4 $ 625.6 $ 552.7 Depreciation and amortization expense (163.9 ) (85.9 ) (282.5 ) (165.4 ) General and administrative expense (49.2 ) (41.6 ) (91.7 ) (79.5 ) Interest expense, net (70.2 ) (35.7 ) (125.1 ) (69.6 ) Other, net (3.6 ) 4.5 (36.5 ) 10.1 Income tax expense (14.8 ) (15.5 ) (30.1 ) (38.1 ) Net income $ 23.8 $ 103.2 $ 59.7 $ 210.2

Significant Accounting Polici26

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Significant Accounting Policies [Abstract]
Accounting Policy Updates	Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the six months ended June 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers.
Goodwill and Intangible Assets	Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. The Partnership evaluates goodwill for impairment at least annually, as of November 30 th
Recent Accounting Pronouncements	Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory

Business Acquisitions (Tables)

Business Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2015
Business Acquisitions [Abstract]
Pro Forma Consolidated Results of Operations	The following summarized unaudited pro forma consolidated statement of operations information for the six months ended June 30, 2015 and June 30, 2014 assumes that the Partnership’s acquisition of APL and our acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed this acquisition as of January 1, 2014, or that the results that will be attained in the future. Pro Forma Results for the Six Months Ended June 30, 2015 June 30, 2014 Revenues $ 3,667.8 $ 5,647.6 Net income 41.7 182.0
Consideration Transferred to Acquire ATLS and APL	The following table summarizes the consideration transferred to acquire ATLS and APL: Fair Value of Consideration Transferred: Cash paid, net of cash acquired (1): TRC $ 745.7 TRP 828.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (2) 5.2 Common units of TRP 2,421.1 Replacement phantom units awarded (2) 15.0 Total $ 5,024.2 (1) Net of cash acquired of $40.8 million, including $7.3 million received in April 2015 by us as part of the Atlas mergers, representing the one-time cash payment from the Partnership for the APL common units owned by ATLS. The one-time cash payment was paid by the Partnership in February 2015 and received by us from the transfer agent in April 2015. (2) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award.
Preliminary Fair Value Determination Related to the Atlas Mergers	As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $557.9 million, which was recorded as goodwill. Preliminary fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 25.1 Assets from risk management activities 102.1 Property, plant and equipment 4,693.2 Investments in unconsolidated affiliates 214.2 Intangible assets 1,204.0 Other long-term assets 6.6 Current liabilities (255.6 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (8.6 ) Other long-term liabilities (9.1 ) Total identifiable net assets 4,579.7 Noncontrolling interest in subsidiaries (113.4 ) Goodwill 557.9 $ 5,024.2

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2015
Inventories [Abstract]
Components of Inventories	June 30, 2015 December 31, 2014 Partnership: Commodities $ 112.7 $ 157.4 Materials and supplies 12.1 11.5 $ 124.8 $ 168.9

Property, Plant and Equipment29

Property, Plant and Equipment and Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment and Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	June 30, 2015 December 31, 2014 Estimated Useful Lives (In Years) Gathering systems $ 6,052.6 $ 2,588.6 5 to 40 Processing and fractionation facilities 2,982.6 1,890.7 5 to 40 Terminaling and storage facilities 1,090.0 1,038.9 5 to 25 Transportation assets 438.7 359.0 10 to 25 Other property, plant and equipment 210.0 149.3 3 to 40 Land 102.7 95.6 - Construction in progress 725.4 399.0 - Property, plant and equipment 11,602.0 6,521.1 Accumulated depreciation (1,917.7 ) (1,696.5 ) Property, plant and equipment, net $ 9,684.3 $ 4,824.6 Intangible assets $ 1,885.6 $ 681.8 20 Accumulated amortization (150.0 ) (89.9 ) Intangible assets, net $ 1,735.6 $ 591.9

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
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 ARO are as follows: Six Months Ended June 30, 2015 Beginning of period $ 57.1 Preliminary fair value of ARO acquired with APL merger 4.0 Change in cash flow estimate 3.8 Accretion expense 2.7 End of period $ 67.6

Investment in Unconsolidated 31

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2015
Investment in Unconsolidated Affiliate [Abstract]
Activity Related to Investment in Unconsolidated Affiliate	The following table shows the activity related to the Partnership’s investments in unconsolidated affiliates: Six Months Ended June 30, 2015 Beginning of period $ 50.2 Preliminary fair value of T2 Joint Ventures acquired 214.2 Equity earnings (1) 0.5 Cash distributions (2) (7.0 ) Cash calls for expansion projects 0.1 End of period $ 258.0 (1) Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015. (2) Includes $0.1 million distributions received in excess of the Partnership’s share of cumulative earnings for the six months ended June 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts Payable and Accrued 32

Accounts Payable and Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Schedule of Accounts Payable and Accrued Liabilities	June 30, 2015 December 31, 2014 Targa Resources Partners LP TRC Non- Partnership Targa Resources Corp. Consolidated Targa Resources Partners LP TRC Non- Partnership Targa Resources Corp. Consolidated Commodities $ 402.5 $ - $ 402.5 $ 416.7 $ - $ 416.7 Other goods and services 105.9 1.4 107.3 108.9 2.2 111.1 Interest 63.3 1.0 64.3 37.3 - 37.3 Compensation and benefits 1.8 29.3 31.1 1.3 44.8 46.1 Income and other taxes 31.6 0.1 31.7 13.6 (1.9 ) 11.7 Other 47.6 4.6 52.2 14.9 0.7 15.6 $ 652.7 $ 36.4 $ 689.1 $ 592.7 $ 45.8 $ 638.5

Debt Obligations (Tables)

Debt Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Obligations [Abstract]
Schedule of Outstanding Debt	June 30, 2015 December 31, 2014 Current: Obligations of the Partnership Accounts receivable securitization facility, due December 2015 (1) $ 124.2 $ 182.8 Long-term: Non-Partnership obligations: TRC Senior secured revolving credit facility, variable rate, due February 2020 (2) 460.0 - TRC Senior secured term loan, variable rate, due February 2022 160.0 - Unamortized discount (2.7 ) - TRC Senior secured revolving credit facility, variable rate, due October 2017 - 102.0 Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due October 2017 (3) 878.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 6 ⅞ 483.6 483.6 Unamortized discount (23.8 ) (25.2 ) Senior unsecured notes, 6 ⅝ 342.1 - Unamortized premium 5.4 - Senior unsecured notes, 6 ⅜ 300.0 300.0 Senior unsecured notes, 5 ¼ 600.0 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 625.0 625.0 Senior unsecured notes, 4 ⅛ 800.0 800.0 Senior unsecured notes, 6 ⅝ 13.1 - Unamortized premium 0.2 - Senior unsecured notes, 4¾% fixed rate, due November 2021 (5) 6.5 - Senior unsecured notes, 5⅞% fixed rate, due August 2023 (5) 48.1 - Unamortized premium 0.6 - Total long-term debt 5,796.1 2,885.4 Total debt $ 5,920.3 $ 3,068.2 Irrevocable standby letters of credit: Letters of credit outstanding under the TRC Senior secured credit facility (2) $ - $ - Letters of credit outstanding under the Partnership senior secured revolving credit facility (3) 20.5 44.1 $ 20.5 $ 44.1 (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) As of , availability under TRC’s $670.0 million senior secured revolving credit facility was $210.0 million. (3) As of , availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $701.5 million. (4) In May 2015, the Partnership exchanged TRP 6⅝% Senior Notes with the same economic terms to holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us. (5) Senior unsecured notes issued by APL entities and acquired in the ATLS mergers. While the Partnership consolidates the debt acquired in the Atlas mergers, neither we nor the Partnership guarantees the acquired debt of APL.
Interest Rates Incurred on Variable-Rate Debt Obligations	The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the six months ended June 30, 2015: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRC senior secured revolving credit facility 2.9% 2.9% TRC senior secured term loan 5.75% 5.75% Partnership's senior secured revolving credit facility 1.9% - 4.3% 2.0% Partnership's accounts receivable securitization facility 0.9% 0.9%
Summary of Results of Tender Offers	The results of the APL Notes Tender Offers were: Senior Notes Outstanding Note Balance Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer payments % Tendered Note Balance after Tender Offers ($ amounts in millions) 6⅝% due 2020 $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% due 2021 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% due 2023 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5

Partnership Units and Related34

Partnership Units and Related Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Partnership Units and Related Matters [Abstract]
Schedule of Distributions	The following table details the distributions declared and/or paid by the Partnership for the six months ended June 30, 2015: 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) June 30, 2015 August 14, 2015 $ 152.5 $ 43.9 (1 ) $ 4.0 $ 200.4 $ 61.4 $ 0.8250 March 31, 2015 May 15, 2015 148.3 41.7 (1 ) 3.9 193.9 59.0 0.8200 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 51.6 0.8100 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

Common Stock and Related Matt35

Common Stock and Related Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Common Stock and Related Matters [Abstract]
Distributions Declared and/or Paid	The following table details the dividends declared and/or paid 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) June 30, 2015 August 17, 2015 $ 49.2 $ 49.0 $ 0.2 $ 0.87500 March 31, 2015 May 18, 2015 46.6 46.4 0.2 0.83000 December 31, 2014 February 17, 2015 32.8 32.6 0.2 0.77500 (1) Represents accrued dividends on restricted stock units that are payable upon vesting.

Earnings per Common Share (Tabl

Earnings per Common Share (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings per Common Share [Abstract]
Earnings 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: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income $ 23.8 $ 103.2 $ 59.7 $ 210.2 Less: Net income attributable to noncontrolling interests 8.6 76.8 41.1 164.2 Net income attributable to common shareholders $ 15.2 $ 26.4 $ 18.6 $ 46.0 Weighted average shares outstanding - basic 55.9 42.0 50.9 42.0 Net income available per common share - basic $ 0.27 $ 0.63 $ 0.37 $ 1.10 Weighted average shares outstanding 55.9 42.0 50.9 42.0 Dilutive effect of unvested stock awards 0.2 0.1 0.1 0.1 Weighted average shares outstanding - diluted (1) 56.1 42.1 51.0 42.1 Net income available per common share - diluted $ 0.27 $ 0.63 $ 0.36 $ 1.09 (1) For the six months ended June 30, 2015, approximately 1,895 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

Derivative Instruments and He37

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities [Abstract]
Notional Volume of Commodity Hedges	At June 30, 2015, the notional volumes of the Partnership’s commodity derivative contracts were: Commodity Instrument Unit 2015 2016 2017 2018 Natural Gas Swaps MMBtu/d 134,141 68,205 23,082 - Natural Gas Basis Swaps MMBtu/d 55,734 18,853 9,041 - Natural Gas Collars MMBtu/d - 7,500 7,500 1,849 NGL Swaps Bbl/d 5,015 2,254 658 - NGL Options/Collars Bbl/d 1,083 920 920 32 Condensate Swaps Bbl/d 1,826 1,082 500 - Condensate Options/Collars Bbl/d 1,605 790 790 101
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 June 30, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 87.3 $ 1.9 $ 44.4 $ - Long-term 40.3 5.3 15.8 - Total derivatives designated as hedging instruments $ 127.6 $ 7.2 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 4.5 $ - $ - $ 5.2 Total derivatives not designated as hedging instruments $ 4.5 $ - $ - $ 5.2 Total current position $ 91.8 $ 1.9 $ 44.4 $ 5.2 Total long-term position 40.3 5.3 15.8 - Total derivatives $ 132.1 $ 7.2 $ 60.2 $ 5.2
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 June 30, 2015 Asset Position Liability Position Asset Position Liability Position Current position Counterparties with offsetting position $ 77.2 $ 1.9 $ 75.3 $ - Counterparties without offsetting position - assets 14.6 - 14.6 - Counterparties without offsetting position - liabilities - - - - 91.8 1.9 89.9 - Long-term position Counterparties with offsetting position 33.8 5.3 28.5 - Counterparties without offsetting position - assets 6.5 - 6.5 - Counterparties without offsetting position - liabilities - - - - 40.3 5.3 35.0 - Total derivatives Counterparties with offsetting position 111.0 7.2 103.8 - Counterparties without offsetting position - assets 21.1 - 21.1 - Counterparties without offsetting position - liabilities - - - - $ 132.1 $ 7.2 $ 124.9 $ - December 31, 2014 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 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
Amounts Recorded in OCI and Amounts Reclassified from OCI to Revenue and Expense	The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Hedging Relationships Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts $ (8.7 ) $ (6.8 ) $ 16.5 $ (18.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Interest expense, net $ - $ (1.1 ) $ - $ (2.4 ) Revenues 16.3 (4.5 ) 24.4 (10.8 ) $ 16.3 $ (5.6 ) $ 24.4 $ (13.2 )
Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated as Hedging Instruments Location of Gain Recognized in Income on Derivatives Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts Revenue $ (4.0 ) $ (0.1 ) $ 3.2 $ (0.3 )
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 2018 based on year-end valuations: June 30, 2015 December 31, 2014 Commodity hedges, before tax (1) $ 52.4 $ 60.3 (1) Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
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: June 30, 2015 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) $ 132.1 $ 132.1 $ - $ 129.0 $ 3.1 Liabilities from commodity derivative contracts (1) 7.2 7.2 - 4.8 2.4 TPL contingent consideration (2) 4.2 4.2 - - 4.2 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 105.7 105.7 - - - TRC Senior secured revolving credit facility 460.0 460.0 - 460.0 - TRC Term Loan 157.3 167.6 - 167.6 - Partnership's Senior secured revolving credit facility 878.0 878.0 - 878.0 - Partnership's Senior unsecured notes 4,300.8 4,360.8 - 4,360.8 - Partnership's accounts receivable securitization facility 124.2 124.2 - 124.2 - (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 - Derivative Instruments and Hedging Activities. 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. (2) See Note 4 – Business Acquisitions.
Reconciliation of the Changes in Fair Value of Financial Instruments Classified As Level 3	T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2014 $ (1.7 ) $ - TPL contingent consideration (Note 4 - Business Acquisitions) - 4.2 New Level 3 instruments (0.7 ) - Transfers out of Level 3 1.7 - Balance, June 30, 2015 $ (0.7 ) $ 4.2

Supplemental Cash Flow Inform39

Supplemental Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Six Months Ended June 30, 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 101.3 $ 62.7 Income taxes paid, net of refunds 13.2 35.9 Non-cash Investing and Financing balance sheet movements: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements 0.3 0.3 Deadstock commodity inventories transferred to property, plant and equipment 0.5 15.9 Impact of capital expenditure accruals on property, plant and equipment (52.9 ) (30.1 ) Transfers from materials and supplies inventory to property, plant and equipment 1.6 1.4 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) Non-cash merger consideration - common units and replacement equity awards $ 2,436.1 $ - Non-cash merger consideration - common shares and replacement equity awards 1,013.7 - Net non-cash balance sheet movements excluded from consolidated statements of cash flows 3,449.8 - Net cash merger consideration included in investing activities 1,574.4 - Total fair value of consideration transferred $ 5,024.2 $ - (1) Interest capitalized on major projects was $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Information [Abstract]
Information by Segment	Reportable segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities: Three Months Ended June 30, 2015 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Consolidated Revenues Sales of commodities $ 434.1 $ 52.6 $ 30.8 $ 861.5 $ 17.1 $ - $ 1,396.1 $ - $ 1,396.1 Fees from midstream services 106.2 7.4 89.6 100.1 - - 303.3 - 303.3 540.3 60.0 120.4 961.6 17.1 - 1,699.4 - 1,699.4 Intersegment revenues Sales of commodities 212.8 57.7 2.0 68.6 - (341.1 ) - - - Fees from midstream services 1.9 - 63.1 5.4 - (70.4 ) - - - 214.7 57.7 65.1 74.0 - (411.5 ) - - - Revenues $ 755.0 $ 117.7 $ 185.5 $ 1,035.6 $ 17.1 $ (411.5 ) $ 1,699.4 $ - $ 1,699.4 Operating margin $ 138.2 $ 6.5 $ 112.7 $ 51.0 $ 17.1 $ - $ 325.5 $ - $ 325.5 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 $ 115.3 $ 13,352.9 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 $ - $ 557.9 Capital expenditures $ 142.7 $ 4.8 $ 74.4 $ 5.9 $ - $ 1.3 $ 229.1 $ - $ 229.1 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations. (2) Total assets include goodwill. Three Months Ended June 30, 2014 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Consolidated Revenues Sales of commodities $ 62.9 $ 89.7 $ 28.9 $ 1,581.7 $ (4.0 ) $ - 1,759.2 $ - $ 1,759.2 Fees from midstream services 43.1 10.5 72.7 115.1 - - 241.4 - 241.4 106.0 100.2 101.6 1,696.8 (4.0 ) - 2,000.6 - 2,000.6 Intersegment revenues Sales of commodities 381.9 163.4 0.8 137.0 - (683.1 ) - - - Fees from midstream services 1.1 - 72.3 7.6 - (81.0 ) - - - 383.0 163.4 73.1 144.6 - (764.1 ) - - - Revenues $ 489.0 $ 263.6 $ 174.7 $ 1,841.4 $ (4.0 ) $ (764.1 ) 2,000.6 $ - $ 2,000.6 Operating margin $ 97.7 $ 21.8 $ 108.6 $ 53.3 $ (4.0 ) $ - 277.4 $ - $ 277.4 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 6,240.0 $ 88.4 $ 6,328.4 Capital expenditures $ 128.4 $ 3.1 $ 67.5 $ 15.5 $ - $ 1.0 215.5 $ - $ 215.5 Six Months Ended June 30, 2015 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Total Revenues Sales of commodities $ 602.0 $ 105.3 $ 58.1 $ 1,994.1 $ 38.8 $ - $ 2,798.3 $ - $ 2,798.3 Fees from midstream services 169.5 16.1 177.4 217.8 - - 580.8 - 580.8 771.5 121.4 235.5 2,211.9 38.8 - 3,379.1 - 3,379.1 Intersegment revenues - Sales of commodities 428.2 120.4 3.2 147.1 - (698.9 ) - - - Fees from midstream services 3.8 - 135.6 9.9 - (149.3 ) - - - 432.0 120.4 138.8 157.0 - (848.2 ) - - - Revenues $ 1,203.5 $ 241.8 $ 374.3 $ 2,368.9 $ 38.8 $ (848.2 ) $ 3,379.1 $ - $ 3,379.1 Operating margin $ 217.3 $ 14.1 $ 238.1 $ 117.3 $ 38.8 $ - $ 625.6 $ - $ 625.6 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 $ 115.3 $ 13,352.9 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 $ - $ 557.9 Capital expenditures $ 235.6 $ 6.0 $ 132.1 $ 8.9 $ - $ 2.3 $ 384.9 $ - $ 384.9 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations. (2) Total assets include goodwill. Six Months Ended June 30, 2014 Partnership Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Partnership TRC Non- Partnership Total Sales of commodities $ 108.7 $ 190.2 $ 49.9 $ 3,505.4 $ (10.1 ) $ - $ 3,844.1 $ - $ 3,844.1 Fees from midstream services 83.9 18.2 140.8 208.3 - - 451.2 - 451.2 192.6 208.4 190.7 3,713.7 (10.1 ) - 4,295.3 - 4,295.3 Intersegment revenues Sales of commodities 782.2 340.4 1.4 267.5 - (1,391.5 ) - - - Fees from midstream services 2.1 - 138.6 15.4 - (156.1 ) - - - 784.3 340.4 140.0 282.9 - (1,547.6 ) - - - Revenues $ 976.9 $ 548.8 $ 330.7 $ 3,996.6 $ (10.1 ) $ (1,547.6 ) $ 4,295.3 $ - $ 4,295.3 Operating margin $ 191.7 $ 47.8 $ 205.4 $ 117.9 $ (10.1 ) $ - $ 552.7 $ - $ 552.7 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 $ 88.4 $ 6,328.4 Capital expenditures $ 227.3 $ 7.4 $ 136.1 $ 18.6 $ - $ 1.5 $ 390.9 $ - $ 390.9
Revenues by Product and Service	The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Sales of commodities: Natural gas $ 443.5 $ 358.1 $ 750.9 $ 750.4 NGL 854.1 1,335.5 1,884.6 2,986.4 Condensate 51.3 41.8 72.8 70.1 Petroleum products 30.1 28.2 56.5 48.3 Derivative activities 17.1 (4.4 ) 33.5 (11.1 ) 1,396.1 1,759.2 2,798.3 3,844.1 Fees from midstream services: Fractionating and treating 54.7 51.7 104.5 98.2 Storage, terminaling, transportation and export 121.6 125.9 257.7 227.1 Gathering and processing 105.7 48.0 174.1 90.6 Other 21.3 15.8 44.5 35.3 303.3 241.4 580.8 451.2 Total revenues $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3
Reconciliation of Operating Margin to Net Income	The following table shows a reconciliation of operating margin to net income for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Reconciliation of operating margin to net income: Operating margin $ 325.5 $ 277.4 $ 625.6 $ 552.7 Depreciation and amortization expense (163.9 ) (85.9 ) (282.5 ) (165.4 ) General and administrative expense (49.2 ) (41.6 ) (91.7 ) (79.5 ) Interest expense, net (70.2 ) (35.7 ) (125.1 ) (69.6 ) Other, net (3.6 ) 4.5 (36.5 ) 10.1 Income tax expense (14.8 ) (15.5 ) (30.1 ) (38.1 ) Net income $ 23.8 $ 103.2 $ 59.7 $ 210.2

Basis of Presentation (Details)

Basis of Presentation (Details) - Jun. 30, 2015 - shares	Total
Partnership Ownership Disclosure [Abstract]
General partner ownership interest (in hundredths)	2.00%
Parent's percentage ownership in the general partner of the Partnership	100.00%
Number of Partnership common units owned (in units)	16,309,594
Limited Partner [Member]
Partnership Ownership Disclosure [Abstract]
General partner ownership interest (in hundredths)	8.90%

Significant Accounting Polici42

Significant Accounting Policies (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Significant Accounting Policies [Abstract]
Unamortized debt issuance costs	$ 37.2	$ 29.9

Business Acquisitions (Details)

Business Acquisitions (Details)	Feb. 27, 2015USD ($)Transaction$ / sharesshares	Mar. 31, 2015USD ($)	Jun. 30, 2015USD ($)$ / shares	Mar. 31, 2015USD ($)	Jun. 30, 2015USD ($)MMcf / dQuartermi$ / shares	Dec. 31, 2014$ / shares
Business Acquisition [Line Items]
Number of separate legal transactions involved in mergers | Transaction	2
Percentage of general partner's interest maintained (in hundredths)					2.00%
Common units par value (in dollars per share) | $ / shares			$ 0.001		$ 0.001	$ 0.001
Acquisition-related expenses					$ 26,600,000
Targa Pipeline Partners LP [Member]
Business Acquisition [Line Items]
Processing capacity (in MMcf/D) | MMcf / d					2,053
Length of additional pipelines (in miles) | mi					12,220
Common Stock [Member]
Business Acquisition [Line Items]
Amount contributed to maintain general partner ownership percentage		$ 52,400,000
Percentage of general partner's interest maintained (in hundredths)		2.00%
Atlas Pipeline Partners [Member]
Business Acquisition [Line Items]
Purchase consideration	$ 5,300,000,000
Acquired debt and all other assumed liabilities included in purchase consideration	1,800,000,000
Payments for notes tendered and settled upon closing of merger	$ 1,200,000,000
Reduction in incentive distribution			$ 9,375,000	$ 9,375,000
Number of successive quarters, annual distribution is paid | Quarter					4
Distribution of common units/shares for each common unit (in shares) | shares	0.5846
Cash payment (in dollars per common unit) | $ / shares	$ 1.26
Common units acquired	$ 2,600,000,000
Closing market price of common share (in dollars per share) | $ / shares	$ 43.82
Cash paid in lieu of unit issuances	$ 6,400,000
Amount contributed to maintain general partner ownership percentage		$ 52,400,000
Percentage of general partner's interest maintained (in hundredths)		2.00%
Atlas Pipeline Partners [Member] | Common Unit Holders [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 128,000,000
Total distribution of common shares (in shares) | shares	58,614,157
Atlas Pipeline Partners [Member] | Class E Preferred Units [Member]
Business Acquisition [Line Items]
Percentage of cumulative redeemable perpetual preferred units (in hundredths)	8.25%
Atlas Pipeline Partners [Member] | Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Cash payment representing accelerated vesting of a portion of employees APL phantom awards	$ 600,000
Total distribution of common shares (in shares) | shares	629,231
Atlas Pipeline Partners [Member] | Change Of Control Payments [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 28,800,000
Atlas Pipeline Partners [Member] | Common Units [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 7,300,000
Atlas Pipeline Partners [Member] | Common Units [Member] | Atlas Energy [Member]
Business Acquisition [Line Items]
Common units owned by parent prior to closing (in units) | shares	5,754,253
Atlas Pipeline Partners [Member] | Revolving Credit Facility [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 701,400,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution					$ 9,375,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution					6,250,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution					2,500,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution					$ 1,250,000
Atlas Energy [Member]
Business Acquisition [Line Items]
Percentage of interest in common units (in hundredths)	100.00%
Purchase consideration	$ 1,600,000,000
Distribution of common units/shares for each common unit (in shares) | shares	0.1809
Cash payment (in dollars per common unit) | $ / shares	$ 9.12
Cash payments related to acquisition	$ 514,700,000
Common units acquired	$ 1,000,000,000
Closing market price of common share (in dollars per share) | $ / shares	$ 99.58
Common units par value (in dollars per share) | $ / shares	$ 0.001
Acquisition-related expenses	$ 11,000,000
Reduction in purchase price	$ (154,700,000)
Atlas Energy [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) | shares	81,740
Atlas Energy [Member] | Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Cash payment related to one-time cash payments and cash settlements of equity awards	$ 4,500,000
Atlas Energy [Member] | Change Of Control Payments [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	149,200,000
Atlas Energy [Member] | Equity Award Settlements [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 88,000,000
Atlas Energy [Member] | Common Units [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) | shares	10,126,532
Common units acquired	$ 147,400,000
Atlas Energy [Member] | Common Units [Member] | Targa Resources Partners LP [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) | shares	3,363,935

Business Acquisitions, Pro Form

Business Acquisitions, Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations (Details) - USD ($) $ in Millions	4 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenues from acquired business	$ 616.8
Net income from acquired business	$ 17.8
Acquisition-related expenses		$ 26.6
Pro forma consolidated results of operations [Abstract]
Revenues		3,667.8	$ 5,647.6
Net income		$ 41.7	$ 182
West Texas LPG Pipeline Limited Partnership [Member]
Pro forma consolidated results of operations [Abstract]
Percentage of equity interest sold (in hundredths)		20.00%
Atlas Resource Partners, LP [Member]
Pro forma consolidated results of operations [Abstract]
Percentage of equity interest sold (in hundredths)		100.00%

Business Acquisitions, Fair Val

Business Acquisitions, Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions		Feb. 27, 2015	Jun. 30, 2015	Jun. 30, 2014
Fair Value of Consideration Transferred [Abstract]
Cash paid, net of cash acquired			$ 1,574.4	$ 0
Total fair value of consideration transferred		$ 5,024.2	5,024.2
Cash acquired from acquisition		40.8
TRC Non-Partnership [Member]
Fair Value of Consideration Transferred [Abstract]
Cash paid, net of cash acquired	[1]	745.7
Total fair value of consideration transferred			0
Targa Resources Partners LP [Member]
Fair Value of Consideration Transferred [Abstract]
Cash paid, net of cash acquired	[1]	828.7
Total fair value of consideration transferred			$ 5,024.2
Restricted Stock Units (RSUs) [Member]
Fair Value of Consideration Transferred [Abstract]
Common shares of TRC	[2]	5.2
Phantom Unit Awards [Member]
Fair Value of Consideration Transferred [Abstract]
Common shares of TRC	[2]	15
Common Units [Member] | Targa Resources Partners LP [Member]
Fair Value of Consideration Transferred [Abstract]
Common shares of TRC		2,421.1
Common Stock [Member]
Fair Value of Consideration Transferred [Abstract]
Common shares of TRC		1,008.5
Atlas Pipeline Partners [Member] | Common Units [Member]
Fair Value of Consideration Transferred [Abstract]
Cash payments related to acquisition		7.3
Atlas Energy [Member]
Fair Value of Consideration Transferred [Abstract]
Cash payments related to acquisition		$ 514.7
[1]	Net of cash acquired of $40.8 million, including $7.3 million received in April 2015 by us as part of the Atlas mergers, representing the one-time cash payment from the Partnership for the APL common units owned by ATLS. The one-time cash payment was paid by the Partnership in February 2015 and received by us from the transfer agent in April 2015.
[2]	The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award.

Business Acquisitions, Prelimin

Business Acquisitions, Preliminary Fair Value Determination (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014	Feb. 27, 2015	Dec. 31, 2014
Preliminary fair value determination [Abstract]
Trade receivables, net							$ 181.1
Other current assets							25.1
Assets from risk management activities							102.1
Property, plant and equipment							4,693.2
Investments in unconsolidated affiliates							214.2
Intangible assets	$ 1,204			$ 1,204			1,204
Other long-term assets							6.6
Current liabilities							(255.6)
Long-term debt							(1,573.3)
Deferred income tax liabilities, net							(8.6)
Other long-term liabilities							(9.1)
Total identifiable net assets							4,579.7
Noncontrolling interest in subsidiaries							(113.4)
Goodwill	557.9			557.9			557.9	$ 0
Total	5,024.2			5,024.2			5,024.2
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization expense	(163.9)		$ (85.9)	(282.5)		$ (165.4)
Equity earnings	$ (1.5)		$ 4.2	$ 0.5	[1]	$ 9.1
Trade receivables, fair value							178.1
Trade receivables, gross amount							178.1
Contractual receivables included in current receivables							3
Contractual receivables included in other long term assets							$ 4.5
Measurement Period Adjustments [Member] | Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization expense		$ (1)
Equity earnings		$ 0.3
[1]	Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015.

Business Acquisitions, Continge

Business Acquisitions, Contingent Consideration, Replacement Restricted Stock Units and Replacement Phantom Units(Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Feb. 27, 2015
Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Vesting period of original term	4 years
Number of common units called by replacement equity unit (in shares)	1
Dividend payment period	60 days
Restricted Stock Units (RSUs) [Member] | Vesting Term One [Member]
Business Acquisition [Line Items]
Vesting percentage original term (in hundredths)	25.00%
Restricted Stock Units (RSUs) [Member] | Vesting Term Two [Member]
Business Acquisition [Line Items]
Vesting percentage original term (in hundredths)	25.00%
Restricted Stock Units (RSUs) [Member] | Vesting Term Three [Member]
Business Acquisition [Line Items]
Vesting percentage original term (in hundredths)	75.00%
Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Number of common units called by replacement equity unit (in shares)	1
Dividend payment period	60 days
Phantom Unit Awards [Member] | Vesting Term One [Member]
Business Acquisition [Line Items]
Vesting percentage original term (in hundredths)	25.00%
Vesting period of original term	4 years
Phantom Unit Awards [Member] | Vesting Term Two [Member]
Business Acquisition [Line Items]
Vesting percentage original term (in hundredths)	33.00%
Vesting period of original term	3 years
Atlas Pipeline Partners [Member]
Business Acquisition [Line Items]
Contingent consideration additional amount	$ 6
Contingent liability acquisition date fair value	4.2	$ 6
Contingent consideration liability lower range	0
Contingent consideration liability higher range	$ 6

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Partnership:
Commodities	$ 112.7	$ 157.4
Materials and supplies	12.1	11.5
Inventories, Net	$ 124.8	$ 168.9

Property, Plant and Equipment49

Property, Plant and Equipment and Intangible Assets (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Feb. 27, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 11,602		$ 6,521.1
Accumulated depreciation	(1,917.7)		(1,696.5)
Property, plant and equipment, net	9,684.3		4,824.6
Finite-Lived Intangible Assets [Line Items]
Intangible assets	1,885.6		681.8
Accumulated amortization	(150)		(89.9)
Intangible assets, net	$ 1,735.6		591.9
Estimated useful lives	20 years
Preliminary value of intangible assets acquired	$ 1,204	$ 1,204
Amortization period of acquired intangible assets used for preparing financial statements	4 months
Estimated annual amortization expense for intangible assets [Abstract]
2,015	$ 130.1
2,016	148.3
2,017	141.5
2,018	127.8
2,019	116.8
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 6,052.6		2,588.6
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	40 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,982.6		1,890.7
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	40 years
Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,090		1,038.9
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	$ 438.7		359
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	$ 210		149.3
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	40 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 102.7		95.6
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 725.4		$ 399

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Changes in aggregate asset retirement obligations [Roll Forward]
Beginning of period	$ 57.1
Preliminary fair value of ARO acquired with APL merger	4
Change in cash flow estimate	3.8	$ 2.1
Accretion expense	2.7	$ 2.2
End of period	$ 67.6

Investment in Unconsolidated 51

Investment in Unconsolidated Affiliates (Details) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015USD ($)JointVenture	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)JointVenture		Jun. 30, 2014USD ($)
Schedule of Equity Method Investments [Line Items]
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture		3		3
Beginning of period				$ 50.2
Preliminary fair value of T2 Joint Ventures acquired				214.2
Equity earnings		$ (1.5)	$ 4.2	0.5	[1]	$ 9.1
Cash distributions	[2]			(7)
Cash calls for expansion projects				0.1
End of period		258		258
Return of capital from unconsolidated affiliate				0.1		$ 3.6
Basis difference on preliminary fair values		$ 39.6		$ 39.6
Preliminary estimated useful lives of the underlying assets				20 years
Gulf Coast Fractionators LP [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)		38.80%		38.80%
T2 LaSalle [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)		75.00%		75.00%
T2 Eagle Ford [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)		50.00%		50.00%
T2 EF Co-Gen [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (in hundredths)		50.00%		50.00%
[1]	Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015.
[2]	Includes $0.1 million distributions received in excess of the Partnership's share of cumulative earnings for the six months ended June 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts Payable and Accrued 52

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$ 402.5	$ 416.7
Other goods and services	107.3	111.1
Interest	64.3	37.3
Compensation and benefits	31.1	46.1
Income and other taxes	31.7	11.7
Other	52.2	15.6
Accounts payable and accrued liabilities	689.1	638.5
Targa Resources Partners LP [Member]
Components of accounts payable and accrued liabilities [Abstract]
Commodities	402.5	416.7
Other goods and services	105.9	108.9
Interest	63.3	37.3
Compensation and benefits	1.8	1.3
Income and other taxes	31.6	13.6
Other	47.6	14.9
Accounts payable and accrued liabilities	652.7	592.7
TRC Non Partnership [Member]
Components of accounts payable and accrued liabilities [Abstract]
Commodities	0	0
Other goods and services	1.4	2.2
Interest	1	0
Compensation and benefits	29.3	44.8
Income and other taxes	0.1	(1.9)
Other	4.6	0.7
Accounts payable and accrued liabilities	$ 36.4	$ 45.8

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
Long-term [Abstract]
Long-term debt		$ 5,796.1	$ 2,885.4
Total debt		5,920.3	3,068.2
Letters of credit outstanding		20.5	44.1
TRC Senior Secured Term Loan due February 2022 [Member]
Long-term [Abstract]
Long-term debt		160	0
Unamortized discount		$ (2.7)	0
Maturity date		Feb. 28, 2022
Senior Secured Credit Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of Interest Rates Incurred (in hundredths)		2.90%
Weighted Average Interest Rate Incurred (in hundredths)		2.90%
Senior Secured Term Loan [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of Interest Rates Incurred (in hundredths)		5.75%
Weighted Average Interest Rate Incurred (in hundredths)		5.75%
Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility due February 2020 [Member]
Long-term [Abstract]
Long-term debt	[1]	$ 460	0
Maturity date		Feb. 29, 2020
Letters of credit outstanding	[1]	$ 0	0
Maximum borrowing capacity		670
Remaining borrowing capacity		210
Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility due 2017 [Member]
Long-term [Abstract]
Long-term debt		$ 0	102
Maturity date		Oct. 31, 2017
Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[2],[3],[4]	$ 13.1	0
Unamortized premium	[4]	$ 0.2	0
Interest rate on fixed rate debt (in hundredths)	[2]	6.625%
Maturity date	[2]	Oct. 31, 2020
Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Long-term [Abstract]
Long-term debt	[3],[4]	$ 6.5	0
Interest rate on fixed rate debt (in hundredths)		4.75%
Maturity date		Nov. 30, 2021
Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Long-term [Abstract]
Long-term debt	[3],[4]	$ 48.1	0
Unamortized premium	[2],[4]	$ 0.6	0
Interest rate on fixed rate debt (in hundredths)		5.875%
Maturity date		Aug. 31, 2023
Targa Resources Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Long-term [Abstract]
Interest rate on fixed rate debt (in hundredths)		6.625%
Targa Resources Partners LP [Member] | Senior Secured Credit Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred, minimum (in hundredths)		1.90%
Range of interest rates incurred, maximum (in hundredths)		4.30%
Weighted Average Interest Rate Incurred (in hundredths)		2.00%
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due 2017 [Member]
Long-term [Abstract]
Long-term debt	[4],[5]	$ 878	0
Maturity date		Oct. 31, 2017
Letters of credit outstanding	[5]	$ 20.5	44.1
Maximum borrowing capacity		1,600
Remaining borrowing capacity		701.5
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 1,100	0
Interest rate on fixed rate debt (in hundredths)		5.00%
Maturity date		Jan. 31, 2018
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 483.6	483.6
Unamortized discount	[4]	$ (23.8)	(25.2)
Interest rate on fixed rate debt (in hundredths)		6.875%
Maturity date		Feb. 28, 2021
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[2],[4]	$ 342.1	0
Unamortized premium	[4]	$ 5.4	0
Interest rate on fixed rate debt (in hundredths)		6.625%
Maturity date		Oct. 31, 2020
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 300	300
Interest rate on fixed rate debt (in hundredths)		6.375%
Maturity date		Aug. 31, 2022
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 600	600
Interest rate on fixed rate debt (in hundredths)		5.25%
Maturity date		May 31, 2023
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 625	625
Interest rate on fixed rate debt (in hundredths)		4.25%
Maturity date		Nov. 30, 2023
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% notes due November 2019 [Member]
Long-term [Abstract]
Long-term debt	[4]	$ 800	800
Interest rate on fixed rate debt (in hundredths)		4.125%
Maturity date		Nov. 30, 2019
Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of Interest Rates Incurred (in hundredths)		0.90%
Weighted Average Interest Rate Incurred (in hundredths)		0.90%
Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility due December 2015 [Member]
Current Obligations of the Partnership [Abstract]
Current debt	[4]	$ 124.2	$ 182.8
Long-term [Abstract]
Maturity date		Dec. 31, 2015
[1]	As of June 30, 2015, availability under TRC's $670.0 million senior secured revolving credit facility was $210.0 million.
[2]	In May 2015, the Partnership exchanged TRP 6.625% Senior Notes with the same economic terms to holders of the 2020 APL Notes, (as defined below) who validly tendered such notes for exchange to us.
[3]	Senior unsecured notes issued by APL entities and acquired in the ATLS mergers. While the Partnership consolidates the debt acquired in the Atlas mergers, neither we nor the Partnership guarantees the acquired debt of APL.
[4]	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.
[5]	As of June 30, 2015, availability under the Partnership's $1.6 billion senior secured revolving credit facility ("TRP Revolver") was $701.5 million.

Debt Obligations, Partnership a

Debt Obligations, Partnership and Merger Financing Activities (Details) - USD ($) $ in Millions	Feb. 27, 2015	Jun. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Apr. 30, 2015
Debt Instrument [Line Items]
Net proceeds from issuance of senior notes						$ 1,100	$ 0
Atlas Energy [Member]
Debt Instrument [Line Items]
Cash payments related to acquisition	$ 514.7
Atlas Pipeline Partners [Member]
Debt Instrument [Line Items]
Cash payments related to change of control payments				$ 28.8
Senior Secured Term Loan [Member] | TRC Credit Agreement [Member]
Debt Instrument [Line Items]
Expiration period for credit facility						7 years
Aggregate principal amount		$ 430				$ 430
Debt instrument discount rate (in hundredths)						1.75%
Cash payments related to change of control payments		160.2				$ 160.2
Repayment of term loan		82	$ 188
Write off of debt discount		1.4	3.3
Write off of debt issuance cost		2.4	$ 5.7
Senior Secured Term Loan [Member] | TRC Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate (in hundredths)						4.75%
Senior Secured Term Loan [Member] | TRC Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | Interest Rate Floor [Member]
Debt Instrument [Line Items]
Debt instrument, floor interest rate (in hundredths)						1.00%
Shelf Offering April 2015 Shelf [Member]
Debt Instrument [Line Items]
Aggregate amount of debt or equity securities allowed under shelf agreement								$ 1,000
Revolving Credit Facility [Member] | TRC Credit Agreement [Member]
Debt Instrument [Line Items]
Expiration period for credit facility						5 years
Aggregate principal amount		670				$ 670
Revolving Credit Facility [Member] | Atlas Pipeline Partners [Member]
Debt Instrument [Line Items]
Cash payments related to acquisition				701.4
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due 2017 [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 1,600				$ 1,600
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | First Amendment [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity				1,600
Additional commitment increase available upon request				$ 300
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | Original Agreement [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity					$ 1,200
Additional commitment increase available upon request					300
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Aggregate principal amount					1,100
Net proceeds from issuance of senior notes					$ 1,089.8

Debt Obligations, APL Senior No

Debt Obligations, APL Senior Notes Tender Offers (Details) - USD ($) $ in Thousands	Apr. 27, 2015	Feb. 27, 2015	Mar. 31, 2015	Feb. 27, 2015
Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Amount Tendered and Paid		$ 1,200,000
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Tendered percentage (in hundredths)	96.30%
APL Senior Notes Tender Offers [Member]
Results of tender offers [Abstract]
Outstanding Note Balance				$ 1,550,000
Amount Tendered and Paid				1,135,500
Premium Paid				16,700
Accrued Interest Paid				11,600
Total Tender Offer payments				1,163,800
Note Balance after Tender Offers		414,500		414,500
APL Senior Notes Tender Offers [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance				500,000
Amount Tendered and Paid				140,100
Premium Paid				2,100
Accrued Interest Paid				3,700
Total Tender Offer payments				$ 145,900
Tendered percentage (in hundredths)				28.02%
Note Balance after Tender Offers		359,900		$ 359,900
APL Senior Notes Tender Offers [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance				400,000
Amount Tendered and Paid				393,500
Premium Paid				5,900
Accrued Interest Paid				5,300
Total Tender Offer payments				$ 404,700
Tendered percentage (in hundredths)				98.38%
Note Balance after Tender Offers		6,500		$ 6,500
APL Senior Notes Tender Offers [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance				650,000
Amount Tendered and Paid				601,900
Premium Paid				8,700
Accrued Interest Paid				2,600
Total Tender Offer payments				$ 613,200
Tendered percentage (in hundredths)				92.60%
Note Balance after Tender Offers		$ 48,100		$ 48,100
APL Senior Notes with Offers Tendered [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Total Tender Offer payments			$ 5,000

Debt Obligations, Debt Redempti

Debt Obligations, Debt Redemption (Details) - USD ($) $ in Thousands	1 Months Ended		2 Months Ended	6 Months Ended
	Mar. 31, 2015	Jan. 31, 2015	Feb. 27, 2015	Jun. 30, 2015	Jun. 30, 2014
Results of tender offers [Abstract]
Repayment of debt				$ 1,168,800	$ 0
APL Senior Notes Tender Offers [Member]
Results of tender offers [Abstract]
Total tender offer payments			$ 1,163,800
APL Senior Notes Tender Offers [Member] | Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Repayment of debt		$ 1,168,800
APL Senior Notes Tender Offers [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Results of tender offers [Abstract]
Total tender offer payments			$ 145,900
APL Senior Notes with Offers Tendered [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Repayment of debt	$ 4,800
Total tender offer payments	$ 5,000

Debt Obligations, Exchange Offe

Debt Obligations, Exchange Offer and Consent Solicitation and TRP Note Guarantees (Details) - Senior Unsecured 6 5/8% Notes due October 2020 [Member] - Atlas Pipeline Partners [Member] - USD ($) $ in Millions	Apr. 27, 2015	Apr. 13, 2015
Debt Instrument [Line Items]
Tendered percentage (in hundredths)	96.30%
Aggregate principal amount outstanding		$ 342.1
Unamortized premium		$ 5.6

Partnership Units and Related58

Partnership Units and Related Matters, Issuances of Common Units (Details) - USD ($) $ in Millions	Feb. 27, 2015	Jul. 31, 2015	Mar. 31, 2015	Jun. 30, 2015
Partnership Equity [Abstract]
General partner ownership interest (in hundredths)				2.00%
Atlas Energy [Member] | Common Units [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)	10,126,532
Atlas Energy [Member] | Common Units [Member] | Targa Resources Partners LP [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)	3,363,935
Atlas Pipeline Partners [Member]
Partnership Equity [Abstract]
Amount contributed to maintain general partner ownership percentage			$ 52.4
General partner ownership interest (in hundredths)			2.00%
Atlas Pipeline Partners [Member] | Common Unit Holders [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)	58,614,157
May 2014 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)				3,590,826
Dollar amount of common units able to sell from equity distribution agreement				$ 400
Net proceeds from public offering				$ 153
Commissions to sales agents, maximum (in hundredths)				1.00%
Amount contributed to maintain general partner ownership percentage				$ 3.1
General partner ownership interest (in hundredths)				2.00%
May 2015 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)				3,222,981
Dollar amount of common units able to sell from equity distribution agreement				$ 1,000
Net proceeds from public offering				$ 140.5
Commissions to sales agents, maximum (in hundredths)				0.75%
Amount contributed to maintain general partner ownership percentage				$ 2.9
General partner ownership interest (in hundredths)				2.00%
May 2015 EDA [Member] | Subsequent Event [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)		563,573
Proceeds from public offering, net of commissions		$ 22.6
Amount contributed to maintain general partner ownership percentage		0.5
Amount contributed subsequent to the reporting period to maintain general partner ownership percentage related to the reporting period		$ 0.9
General partner ownership interest (in hundredths)		2.00%
Amount which remain available under the shelf agreement		$ 835.6

Partnership Units and Related59

Partnership Units and Related Matters, Distributions (Details) - USD ($)		3 Months Ended				6 Months Ended
		Jun. 30, 2015	Mar. 31, 2015		Dec. 31, 2014	Jun. 30, 2015
Partnership Equity [Abstract]
Number of days from end of each quarter by when cash is distributed to unit holders						45 days
Distributions Declared [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date paid or to be paid		Aug. 14, 2015
Distributions to limited partners common		$ 152,500,000
Distributions to general partners (Incentive distribution rights)	[1]	43,900,000
Distributions to general partner (2%)		4,000,000
Total distributions to general and limited partners		200,400,000
Distributions to Targa Resources Corp.		$ 61,400,000
Distributions per limited partner unit (in dollars per unit)		$ 0.8250
Distributions Paid [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date paid or to be paid			May 15, 2015		Feb. 13, 2015
Distributions to limited partners common			$ 148,300,000		$ 96,300,000
Distributions to general partners (Incentive distribution rights)			41,700,000	[1]	38,400,000
Distributions to general partner (2%)			3,900,000		2,700,000
Total distributions to general and limited partners			193,900,000		137,400,000
Distributions to Targa Resources Corp.			$ 59,000,000		$ 51,600,000
Distributions per limited partner unit (in dollars per unit)			$ 0.8200		$ 0.8100
Atlas Pipeline Partners [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Reduction in incentive distribution		$ 9,375,000	$ 9,375,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Reduction in incentive distribution						$ 9,375,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Reduction in incentive distribution						6,250,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Reduction in incentive distribution						2,500,000
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Reduction in incentive distribution						$ 1,250,000
[1]	Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

Common Stock and Related Matt60

Common Stock and Related Matters (Details) - USD ($) $ / shares in Units, $ in Millions		Feb. 27, 2015	Mar. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Value of shares issued in exchange for ATLS common units				$ 0.1		$ 0	$ 0.1
Common stock closing market price (in dollars per share)		$ 99.58
Common stock net proceeds of public offering							$ 336.6
General partnership interest (in hundredths)							2.00%
Dividends Payable [Line Items]
Amount of dividend paid							$ 78.9	$ 52.7
Common Stock [Member]
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Number of shares issued in public offering (in shares)			3,250,000				3,738,000
Common stock issued price per share (in dollars per share)			$ 91		$ 91
Common stock net proceeds of public offering			$ 292.8				$ 0
Number of additional shares sold in public offering (in shares)			487,500
Additional net proceeds from public offering pursuant to exercise of underwriters' overallotment option			$ 43.9
Payments to capital contribution in partnership			$ 52.4
General partnership interest (in hundredths)			2.00%
Dividend Declared, Q2 2015 [Member]
Dividends Payable [Line Items]
Date paid or to be paid				Aug. 17, 2015
Total dividend declared				$ 49.2
Amount of dividend paid				49
Accrued dividends	[1]			$ 0.2			$ 0.2
Dividend declared per share of common stock (in dollars per share)				$ 0.87500
Dividend Declared, Q1 2015 [Member]
Dividends Payable [Line Items]
Date paid or to be paid					May 18, 2015
Total dividend declared					$ 46.6
Amount of dividend paid					46.4
Accrued dividends	[1]		$ 0.2		$ 0.2
Dividend declared per share of common stock (in dollars per share)					$ 0.83000
Dividend Declared, Q4 2014 [Member]
Dividends Payable [Line Items]
Date paid or to be paid						Feb. 17, 2015
Total dividend declared						$ 32.8
Amount of dividend paid						32.6
Accrued dividends	[1]					$ 0.2
Dividend declared per share of common stock (in dollars per share)						$ 0.77500
Atlas Energy [Member]
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Number of shares issued in exchange for ATLS common units (in shares)		10,126,532
Value of shares issued in exchange for ATLS common units		$ 1,000
Replacement restricted stock units (in shares)		81,740
[1]	Represents accrued dividends on restricted stock units that are payable upon vesting.

Earnings per Common Share (Deta

Earnings per Common Share (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings per Common Share [Abstract]
Net income		$ 23.8	$ 103.2	$ 59.7	$ 210.2
Less: Net income attributable to noncontrolling interests		8.6	76.8	41.1	164.2
Net income attributable to common shareholders		$ 15.2	$ 26.4	$ 18.6	$ 46
Weighted average shares outstanding - basic (in shares)		55,900,000	42,000,000	50,900,000	42,000,000
Net income available per common share - basic (in dollars per share)		$ 0.27	$ 0.63	$ 0.37	$ 1.10
Weighted average shares outstanding (in shares)		55,900,000	42,000,000	50,900,000	42,000,000
Dilutive effect of unvested stock awards (in shares)		200,000	100,000	100,000	100,000
Weighted average shares outstanding - diluted (in shares)	[1]	56,100,000	42,100,000	51,000,000	42,100,000
Net income available per common share - diluted (in dollars per share)		$ 0.27	$ 0.63	$ 0.36	$ 1.09
Number of shares excluded from the computation of diluted earnings per share (in shares)				1,895
[1]	For the six months ended June 30, 2015, approximately 1,895 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

Derivative Instruments and He62

Derivative Instruments and Hedging Activities (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2015USD ($)MMBTUbbl	Feb. 27, 2015USD ($)
Derivative [Line Items]
Fair value of derivative assets | $			$ 102.1
Atlas Pipeline Partners [Member]
Derivative [Line Items]
Fair value of derivative assets | $			102.1
Fair value of derivative contracts received as component of derivative contract settlement | $	$ 23.1	$ 31.5
Ineffectiveness gains (losses) | $	(0.2)	$ 0.9
Swaps [Member] | Year 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		134,141
Swaps [Member] | Year 2015 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		5,015
Swaps [Member] | Year 2015 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,826
Swaps [Member] | Year 2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		68,205
Swaps [Member] | Year 2016 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		2,254
Swaps [Member] | Year 2016 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,082
Swaps [Member] | Year 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		23,082
Swaps [Member] | Year 2017 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		658
Swaps [Member] | Year 2017 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		500
Swaps [Member] | Year 2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		0
Swaps [Member] | Year 2018 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		0
Swaps [Member] | Year 2018 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		0
Basis Swaps [Member] | Year 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		55,734
Basis Swaps [Member] | Year 2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		18,853
Basis Swaps [Member] | Year 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		9,041
Basis Swaps [Member] | Year 2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		0
Collars [Member] | Year 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		0
Collars [Member] | Year 2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		7,500
Collars [Member] | Year 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		7,500
Collars [Member] | Year 2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) | MMBTU		1,849
Option/Collars [Member] | Year 2015 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,083
Option/Collars [Member] | Year 2015 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,605
Option/Collars [Member] | Year 2016 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		920
Option/Collars [Member] | Year 2016 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		790
Option/Collars [Member] | Year 2017 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		920
Option/Collars [Member] | Year 2017 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		790
Option/Collars [Member] | Year 2018 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		32
Option/Collars [Member] | Year 2018 [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		101
Options [Member] | Crude Oil [Member] | Atlas Pipeline Partners [Member]
Derivative [Line Items]
Fair value of derivative assets | $			$ 7.7
Mark-to-market losses | $	$ 1.3	$ 0.2

Derivative Instruments and He63

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets	$ 132.1	$ 60.2
Derivative liabilities	7.2	5.2
Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	91.8	44.4
Long-Term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	40.3	15.8
Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1.9	5.2
Long-Term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	5.3	0
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	127.6	60.2
Derivative liabilities	7.2	0
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	87.3	44.4
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-Term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	40.3	15.8
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1.9	0
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-Term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	5.3	0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	4.5	0
Derivative liabilities	0	5.2
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	4.5	0
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0	$ 5.2

Derivative Instruments and He64

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Pro forma net presentation, asset	$ 124.9
Gross asset	132.1	$ 60.2
Pro forma net presentation, asset, total	124.9	55.8
Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	111	35.5
Gross liability	7.2	4.4
Pro forma net presentation, asset	103.8	31.1
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	21.1	24.7
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	91.8	44.4
Pro forma net presentation, asset, current	89.9	40
Current Position [Member] | Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	77.2	35.5
Gross liability	1.9	4.4
Pro forma net presentation, asset	75.3	31.1
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	14.6	8.9
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	40.3	15.8
Pro forma net presentation, asset, noncurrent	35	15.8
Long-term Position [Member] | Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	33.8	0
Gross liability	5.3	0
Pro forma net presentation, asset	28.5	0
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	$ 6.5	$ 15.8

Derivative Instruments and He65

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivative Liability [Abstract]
Gross liability	$ 7.2	$ 5.2
Pro forma net presentation, liability, total	0	0.8
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0	0.8
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	1.9	5.2
Pro forma net presentation, liability, current	0	0.8
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0	0.8
Long-term Position [Member]
Derivative Liability [Abstract]
Gross liability	5.3	0
Pro forma net presentation, liability, noncurrent	0	0
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	$ 0	$ 0

Derivative Instruments and He66

Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)		$ 16.3	$ (5.6)	$ 24.4	$ (13.2)
Cash Flow Hedging [Member] | Interest Expense, Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)		0	(1.1)	0	(2.4)
Cash Flow Hedging [Member] | Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)		16.3	(4.5)	24.4	(10.8)
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)		(8.7)	(6.8)	16.5	(18.6)
Deferred gains (losses) included in accumulated OCI, before tax	[1]	52.4		52.4		$ 60.3
Net losses on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months		36.1		36.1
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives		$ (4)	$ (0.1)	$ 3.2	$ (0.3)
[1]	Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Millions		6 Months Ended
		Jun. 30, 2015USD ($)Swap	Dec. 31, 2014USD ($)
Fair Value Measurements [Abstract]
Derivative financial instruments, fair value, net		$ 124.9
Derivative fair value of net asset if commodity price increases by 10 percent		92.5
Derivative fair value of net asset if commodity price decreases by 10 percent		$ 154.6
Number of natural gas basis swaps categorized as Level 3 | Swap		29
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts		$ 124.9	$ 55.8
Liabilities from commodity derivative contracts		0	$ 0.8
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] [Roll Forward]
Balance, beginning of period		(1.7)
TPL contingent consideration (Note 4 - Business Acquisitions)		0
New Level 3 instruments		(0.7)
Transfers out of Level 3		1.7
Balance, end of period		(0.7)
Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	0
Liabilities from commodity derivative contracts	[1]	0
TPL contingent consideration	[2]	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0
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
Level 1 [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0
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
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
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
Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	129
Liabilities from commodity derivative contracts	[1]	4.8
TPL contingent consideration	[2]	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0
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		460
Level 2 [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		167.6
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		878
Level 2 [Member] | Partnership's Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,360.8
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		124.2
Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	3.1
Liabilities from commodity derivative contracts	[1]	2.4
TPL contingent consideration	[2]	4.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0
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
Level 3 [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0
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
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
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
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	132.1
Liabilities from commodity derivative contracts	[1]	7.2
TPL contingent consideration	[2]	4.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		105.7
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		460
Carrying Value [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		157.3
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		878
Carrying Value [Member] | Partnership's Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,300.8
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		124.2
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	132.1
Liabilities from commodity derivative contracts	[1]	7.2
TPL contingent consideration	[2]	4.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		105.7
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		460
Fair Value [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		167.6
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		878
Fair Value [Member] | Partnership's Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,360.8
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		124.2
Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period		0
TPL contingent consideration (Note 4 - Business Acquisitions)		4.2
New Level 3 instruments		0
Transfers out of Level 3		0
Balance, end of period		$ 4.2
[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.
[2]	See Note 4 - Business Acquisitions

Contingencies (Details)

Contingencies (Details) - Atlas Unitholder Litigation [Member] - Unitholder	2 Months Ended	3 Months Ended
	Nov. 30, 2014	Dec. 31, 2014
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

Supplemental Cash Flow Inform69

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		Feb. 27, 2015	Jun. 30, 2015	Jun. 30, 2014
Cash [Abstract]
Interest paid, net of capitalized interest	[1]		$ 101.3	$ 62.7
Income taxes paid, net of refunds			13.2	35.9
Non-cash Investing and Financing balance sheet movements [Abstract]
Debt additions and retirements related to exchange of TRP 6.625% Notes for APL 6.625% Notes			342.1	0
Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements			0.3	0.3
Deadstock commodity inventories transferred to property, plant and equipment			0.5	15.9
Impact of capital expenditure accruals on property, plant and equipment			(52.9)	(30.1)
Transfers from materials and supplies inventory to property, plant and equipment			1.6	1.4
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate			3.8	2.1
Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) [Abstract]
Non-cash merger consideration - common units and replacement equity awards			2,436.1	0
Non-cash merger consideration - common shares and replacement equity awards			1,013.7	0
Net non-cash balance sheet movements excluded from consolidated statements of cash flows			3,449.8	0
Net cash merger consideration included in investing activities			1,574.4	0
Total fair value of consideration transferred			5,024.2	0
Interest capitalized on major projects			$ 5.5	$ 11.5
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt (in hundredths)			6.625%
Targa Resources Partners LP [Member]
Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) [Abstract]
Net cash merger consideration included in investing activities	[2]	$ 828.7
Targa Resources Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt (in hundredths)			6.625%
[1]	Interest capitalized on major projects was $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014.
[2]	Net of cash acquired of $40.8 million, including $7.3 million received in April 2015 by us as part of the Atlas mergers, representing the one-time cash payment from the Partnership for the APL common units owned by ATLS. The one-time cash payment was paid by the Partnership in February 2015 and received by us from the transfer agent in April 2015.

Segment Information, Revenues a

Segment Information, Revenues and Operating Margin (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)DivisionSegment	Jun. 30, 2014USD ($)
Segment Reporting Information [Line Items]
Number of divisions | Division			2
Sale of commodities	$ 1,396.1	$ 1,759.2	$ 2,798.3	$ 3,844.1
Fees from midstream services	303.3	241.4	580.8	451.2
Revenues	1,699.4	2,000.6	3,379.1	4,295.3
Operating margin	325.5	277.4	625.6	552.7
Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	1,396.1	1,759.2	2,798.3	3,844.1
Fees from midstream services	303.3	241.4	580.8	451.2
Revenues	1,699.4	2,000.6	3,379.1	4,295.3
Operating margin	325.5	277.4	625.6	552.7
TRC Non-Partnership [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	0	0	0
Operating margin	0	0	$ 0	0
Gathering and Processing [Member]
Segment Reporting Information [Line Items]
Number of reportable segments per division | Segment			2
Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	755	489	$ 1,203.5	976.9
Operating margin	138.2	97.7	217.3	191.7
Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	117.7	263.6	241.8	548.8
Operating margin	6.5	21.8	$ 14.1	47.8
Logistics and Marketing [Member]
Segment Reporting Information [Line Items]
Number of reportable segments per division | Segment			2
Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	185.5	174.7	$ 374.3	330.7
Operating margin	112.7	108.6	238.1	205.4
Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	1,035.6	1,841.4	2,368.9	3,996.6
Operating margin	51	53.3	117.3	117.9
Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	17.1	(4)	38.8	(10.1)
Operating margin	17.1	(4)	38.8	(10.1)
Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Revenues	(411.5)	(764.1)	(848.2)	(1,547.6)
Operating margin	0	0	0	0
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	434.1	62.9	602	108.7
Fees from midstream services	106.2	43.1	169.5	83.9
Revenues	540.3	106	771.5	192.6
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	52.6	89.7	105.3	190.2
Fees from midstream services	7.4	10.5	16.1	18.2
Revenues	60	100.2	121.4	208.4
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	30.8	28.9	58.1	49.9
Fees from midstream services	89.6	72.7	177.4	140.8
Revenues	120.4	101.6	235.5	190.7
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	861.5	1,581.7	1,994.1	3,505.4
Fees from midstream services	100.1	115.1	217.8	208.3
Revenues	961.6	1,696.8	2,211.9	3,713.7
Operating Segments [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	17.1	(4)	38.8	(10.1)
Fees from midstream services	0	0	0	0
Revenues	17.1	(4)	38.8	(10.1)
Operating Segments [Member] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	0	0	0
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	0	0	0
Intersegment Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	0	0	0
Intersegment Eliminations [Member] | TRC Non-Partnership [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	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	212.8	381.9	428.2	782.2
Fees from midstream services	1.9	1.1	3.8	2.1
Revenues	214.7	383	432	784.3
Intersegment Eliminations [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	57.7	163.4	120.4	340.4
Fees from midstream services	0	0	0	0
Revenues	57.7	163.4	120.4	340.4
Intersegment Eliminations [Member] | Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	2	0.8	3.2	1.4
Fees from midstream services	63.1	72.3	135.6	138.6
Revenues	65.1	73.1	138.8	140
Intersegment Eliminations [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	68.6	137	147.1	267.5
Fees from midstream services	5.4	7.6	9.9	15.4
Revenues	74	144.6	157	282.9
Intersegment Eliminations [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	0	0	0	0
Fees from midstream services	0	0	0	0
Revenues	0	0	0	0
Intersegment Eliminations [Member] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Segment Reporting Information [Line Items]
Sale of commodities	(341.1)	(683.1)	(698.9)	(1,391.5)
Fees from midstream services	(70.4)	(81)	(149.3)	(156.1)
Revenues	$ (411.5)	$ (764.1)	$ (848.2)	$ (1,547.6)

Segment Information, Other Fina

Segment Information, Other Financial Information (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2015		Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014	Feb. 27, 2015	Dec. 31, 2014
Other financial information [Abstract]
Total assets		$ 13,352.9		$ 6,328.4	$ 13,352.9		$ 6,328.4		$ 6,453.5
Goodwill		557.9			557.9			$ 557.9	$ 0
Capital expenditures		229.1		215.5	384.9		390.9
Business acquisitions		5,024.2			5,024.2			$ 5,024.2
Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	557.9			557.9
Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets				6,240			6,240
Capital expenditures		229.1		215.5	384.9		390.9
Business acquisitions		5,024.2			5,024.2
Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	557.9			557.9
TRC Non-Partnership [Member]
Other financial information [Abstract]
Total assets				88.4			88.4
Capital expenditures		0		0	0		0
Business acquisitions		0			0
TRC Non-Partnership [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	0			0
Reportable Segments [Member]
Other financial information [Abstract]
Total assets	[2]	13,352.9			13,352.9
Reportable Segments [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets	[2]	13,237.6			13,237.6
Reportable Segments [Member] | TRC Non-Partnership [Member]
Other financial information [Abstract]
Total assets	[2]	115.3			115.3
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		10,116.7	[2]	3,338.6	10,116.7	[2]	3,338.6
Capital expenditures		142.7		128.4	235.6		227.3
Business acquisitions		5,024.2			5,024.2
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	557.9			557.9
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		350	[2]	377	350	[2]	377
Capital expenditures		4.8		3.1	6		7.4
Business acquisitions		0			0
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	0			0
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		1,831.2	[2]	1,606	1,831.2	[2]	1,606
Capital expenditures		74.4		67.5	132.1		136.1
Business acquisitions		0			0
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	0			0
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		475	[2]	799.4	475	[2]	799.4
Capital expenditures		5.9		15.5	8.9		18.6
Business acquisitions		0			0
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	0			0
Operating Segments [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		132.2	[2]	3.5	132.2	[2]	3.5
Capital expenditures		0		0	0		0
Business acquisitions		0			0
Operating Segments [Member] | Other Segment [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	0			0
Operating Segments [Member] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]
Other financial information [Abstract]
Total assets		332.5	[2]	115.5	332.5	[2]	115.5
Capital expenditures		1.3		$ 1	2.3		$ 1.5
Business acquisitions		0			0
Operating Segments [Member] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member] | Special GP Interest [Member]
Other financial information [Abstract]
Goodwill	[1]	$ 0			$ 0
[1]	Total assets include goodwill.
[2]	Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with Partnership's debt obligations.

Segment Information, Revenues b

Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenue from External Customer [Line Items]
Sale of commodities	$ 1,396.1	$ 1,759.2	$ 2,798.3	$ 3,844.1
Fees from midstream services	303.3	241.4	580.8	451.2
Total revenues	1,699.4	2,000.6	3,379.1	4,295.3
Natural Gas [Member]
Revenue from External Customer [Line Items]
Sale of commodities	443.5	358.1	750.9	750.4
NGL [Member]
Revenue from External Customer [Line Items]
Sale of commodities	854.1	1,335.5	1,884.6	2,986.4
Condensate [Member]
Revenue from External Customer [Line Items]
Sale of commodities	51.3	41.8	72.8	70.1
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sale of commodities	30.1	28.2	56.5	48.3
Derivative Activities [Member]
Revenue from External Customer [Line Items]
Sale of commodities	17.1	(4.4)	33.5	(11.1)
Fractionating and Treating [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	54.7	51.7	104.5	98.2
Storage, Terminaling, Transportation and Export [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	121.6	125.9	257.7	227.1
Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	105.7	48	174.1	90.6
Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	$ 21.3	$ 15.8	$ 44.5	$ 35.3

Segment Information, Reconcilia

Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reconciliation of operating margin to net income [Abstract]
Operating margin	$ 325.5	$ 277.4	$ 625.6	$ 552.7
Depreciation and amortization expense	(163.9)	(85.9)	(282.5)	(165.4)
General and administrative expense	(49.2)	(41.6)	(91.7)	(79.5)
Interest expense, net	(70.2)	(35.7)	(125.1)	(69.6)
Other, net	(3.6)	4.5	(36.5)	10.1
Income tax expense	(14.8)	(15.5)	(30.1)	(38.1)
Net income	$ 23.8	$ 103.2	$ 59.7	$ 210.2