Targa Resources (TRGP) 10-Q 4 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 01, 2017
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 Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		198,105,583
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017		Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 80		$ 73.5
Trade receivables, net of allowances of $0.1 and $0.9 million at March 31, 2017 and December 31, 2016	537.7		674.6
Inventories	75.5		137.7
Assets from risk management activities	23.9		16.8
Income tax receivable	70.6		67.8
Other current assets	24.4		36.4
Total current assets	812.1		1,006.8
Property, plant and equipment	12,957		12,518.7
Accumulated depreciation	(2,993.6)		(2,827.7)
Property, plant and equipment, net	9,963.4		9,691
Intangible assets, net	2,238.8		1,654
Goodwill, net	369		210
Long-term assets from risk management activities	21.6		5.1
Investments in unconsolidated affiliates	227		240.8
Other long-term assets	21.9		63.5
Total assets	13,653.8	[1]	12,871.2
Current liabilities:
Accounts payable and accrued liabilities	867.2		843.5
Liabilities from risk management activities	22.2		49.1
Current maturities of debt	534.9		275
Total current liabilities	1,424.3		1,167.6
Long-term debt	4,213.3		4,606
Long-term liabilities from risk management activities	7.9		26.1
Deferred income taxes, net	951.6		941.2
Other long-term liabilities	688.9		215.1
Contingencies (see Note 18)	0		0
Targa Resources Corp. stockholders' equity:
Common stock value	0.2		0.2
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no shares issued and outstanding)	0		0
Additional paid-in capital	5,986		5,506.2
Receivables from common stock issuances	(19.6)		0
Retained earnings (deficit)	(250.5)		(187.3)
Accumulated other comprehensive income (loss)	6.5		(38.3)
Treasury stock, at cost (522,699 shares as of March 31, 2017 and 513,880 as of December 31, 2016)	(32.7)		(32.2)
Total Targa Resources Corp. stockholders' equity	5,689.9		5,248.6
Noncontrolling interests in subsidiaries	481		475.8
Total owners' equity	6,170.9		5,724.4
Total liabilities, Series A Preferred Stock and owners' equity	13,653.8		12,871.2
Series A Preferred Stock [Member]
Current liabilities:
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, issued and outstanding 965,100 shares), net of discount (see Note 12)	$ 196.9		$ 190.8
[1]	Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Trade receivables, allowances	$ 0.1	$ 0.9
Targa Resources Corp. stockholders' 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)	197,162,557	185,234,405
Common stock, shares outstanding (in shares)	196,639,858	184,720,525
Preferred stock, par value (in dollar per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	98,800,000	98,800,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury stock, shares (in shares)	522,699	513,880
Series A Preferred Stock [Member]
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Preferred Series A Liquidation Stock Percentage	9.50%	9.50%
Preferred Stock, Liquidation Preference Per Share	$ 1,000	$ 1,000
Preferred Stock, Shares Authorized	1,200,000	1,200,000
Preferred Stock, Shares Issued	965,100	965,100
Preferred Stock, Shares Outstanding	965,100	965,100

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Sales of commodities	$ 1,858.1	$ 1,171
Fees from midstream services	254.5	271.4
Total revenues	2,112.6	1,442.4
Costs and expenses:
Product purchases	1,654.2	1,011
Operating expenses	151.9	132.1
Depreciation and amortization expense	191.1	193.5
General and administrative expense	48.7	45.3
Goodwill impairment	0	24
Other operating (income) expense	16.2	1
Income from operations	50.5	35.5
Other income (expense):
Interest expense, net	(63)	(52.9)
Equity earnings (loss)	(12.6)	(4.8)
Gain (loss) from financing activities	(5.8)	24.7
Other	(8.5)	(0.1)
Income (loss) before income taxes	(39.4)	2.4
Income tax (expense) benefit	(71.1)	(3.1)
Net income (loss)	(110.5)	(0.7)
Less: Net income attributable to noncontrolling interests	8.8	2
Net income (loss) attributable to Targa Resources Corp.	(119.3)	(2.7)
Dividends on Series A preferred stock	22.9	3.8
Deemed dividends on Series A preferred stock	6.1	0
Net income (loss) attributable to common shareholders	$ (148.3)	$ (6.5)
Net income (loss) per common share - basic	$ (0.77)	$ (0.06)
Net income (loss) per common share - diluted	$ (0.77)	$ (0.06)
Weighted average shares outstanding - basic	191.8	106.6
Weighted average shares outstanding - diluted	191.8	106.6
Dividends per common share declared for the period	$ 0.91	$ 0.91

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income (loss) attributable to Targa Resources Corp.	$ (119.3)	$ (2.7)
Commodity hedging contracts:
Other comprehensive income (loss) attributable to Targa Resources Corp., pre-tax	72.3	(30.1)
Other comprehensive income (loss) attributable to Targa Resources Corp., related income tax	(27.5)	11.7
Other comprehensive income (loss) attributable to Targa Resources Corp., after tax	44.8	(18.4)
Comprehensive income (loss) attributable to Targa Resources Corp.	(74.5)	(21.1)
Net income (loss) attributable to noncontrolling interests	8.8	2
Commodity hedging contracts:
Other comprehensive income (loss) attributable to noncontrolling interests, pre-tax	0	12.6
Other comprehensive income (loss) attributable to noncontrolling interests, related income tax	0	0
Other comprehensive income (loss) attributable to noncontrolling interests, after tax	0	12.6
Comprehensive income (loss) attributable to noncontrolling interests	8.8	14.6
Total
Net income (loss)	(110.5)	(0.7)
Commodity hedging contracts:
Other comprehensive income (loss) attributable to Targa Resources Corp., pre-tax	72.3	(17.5)
Other comprehensive income (loss) attributable to Targa Resources Corp., related income tax	(27.5)	11.7
Other comprehensive income (loss) attributable to Targa Resources Corp., after tax	44.8	(5.8)
Total comprehensive income (loss)	(65.7)	(6.5)
Commodity Contracts [Member]
Commodity hedging contracts:
Change in fair value, pre-tax	66.2	(17.1)
Change in fair value, related income tax	(25.2)	6.6
Change in fair value, after tax	41	(10.5)
Settlements reclassified to revenues, pre-tax	6.1	(13)
Settlements reclassified to revenues, related income tax	(2.3)	5.1
Settlements reclassified to revenues, after tax	3.8	(7.9)
Commodity hedging contracts:
Change in fair value, pre-tax	0	23.8
Change in fair value, related income tax	0	0
Change in fair value, after tax	0	23.8
Settlements reclassified to revenues, pre-tax	0	(11.2)
Settlements reclassified to revenues, related income tax	0	0
Settlements reclassified to revenues, after tax	0	(11.2)
Commodity hedging contracts:
Change in fair value, pre-tax	66.2	6.7
Change in fair value, related income tax	(25.2)	6.6
Change in fair value, after tax	41	13.3
Settlements reclassified to revenues, pre-tax	6.1	(24.2)
Settlements reclassified to revenues, related income tax	(2.3)	5.1
Settlements reclassified to revenues, after tax	$ 3.8	$ (19.1)

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK (Unaudited) - USD ($) shares in Thousands, $ in Millions	Total	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]	Series A Preferred Stock [Member]
Balance at Dec. 31, 2015	$ 6,250.2	$ 0.1	$ 1,457.4	$ 26.9	$ 5.7	$ (28.7)	$ 4,788.8
Balance (in shares) at Dec. 31, 2015		56,020				426
Series A Preferred Stock at Dec. 31, 2015								$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	8		5.8				2.2
Distribution equivalent rights	(3.7)		(3.5)				(0.2)
Shares issued under compensation program (in shares)		44
Shares and units tendered for tax withholding obligations	(0.3)					$ (0.2)	(0.1)
Shares and units tendered for tax withholding obligations (in shares)		(9)				9
Series A Preferred Stock								173.6
Series A Preferred Stock dividends
Dividends	(3.8)			(3.8)
Common stock dividends
Dividends declared	(51.1)			(51.1)
Dividends in excess of retained earnings			(28)	28
Distributions to noncontrolling interests	(143.8)						(143.8)
Contributions from noncontrolling interests	6						6
Acquisition of TRP noncontrolling common interests, net of acquisition costs and deferred income taxes (in shares)		104,526
Other comprehensive income (loss)	(5.8)				(18.4)		12.6
Net income (loss)	(0.7)			(2.7)			2
Balance at Mar. 31, 2016	5,880.7	$ 0.2	5,321.5	(2.7)	43	$ (28.9)	547.6
Balance (in shares) at Mar. 31, 2016		160,581				435
Series A Preferred Stock at Mar. 31, 2016								173.6
Common stock dividends
Issuance of Series A Preferred and detachable warrants	796.8		796.8
Acquisition of TRP noncontrolling common interests, net of acquisition costs and deferred income taxes	(971.1)	$ 0.1	3,093		55.7		(4,119.9)
Balance at Dec. 31, 2016	5,724.4	$ 0.2	5,506.2	(187.3)	(38.3)	$ (32.2)	475.8
Balance (in shares) at Dec. 31, 2016		184,721				514
Series A Preferred Stock at Dec. 31, 2016								190.8
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Impact of accounting standard adoption (see Note 3)	56.1			56.1
Compensation on equity grants	10.8		10.8
Distribution equivalent rights	(2.2)		(2.2)
Shares issued under compensation program (in shares)		42				0
Shares and units tendered for tax withholding obligations	(0.5)					$ (0.5)
Shares and units tendered for tax withholding obligations (in shares)		(9)				9
Issuance of common stock	676.8		676.8
Issuance of common stock (in shares)		11,886
Receivables from common stock offerings	(19.6)		(19.6)
Series A Preferred Stock dividends
Dividends	(22.9)			(22.9)
Dividends in excess of retained earnings			(22.9)	22.9
Deemed dividends - accretion of beneficial conversion feature	(6.1)		(6.1)					6.1
Common stock dividends
Dividends declared	(176.6)			(176.6)
Dividends in excess of retained earnings			(176.6)	176.6
Distributions to noncontrolling interests	(12.5)						(12.5)
Contributions from noncontrolling interests	8.9						8.9
Other comprehensive income (loss)	44.8				44.8
Net income (loss)	(110.5)			(119.3)			8.8
Balance at Mar. 31, 2017	$ 6,170.9	$ 0.2	$ 5,966.4	$ (250.5)	$ 6.5	$ (32.7)	$ 481
Balance (in shares) at Mar. 31, 2017		196,640				523
Series A Preferred Stock at Mar. 31, 2017								$ 196.9

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities
Net income (loss)		$ (110.5)	$ (0.7)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		3.1	4.2
Compensation on equity grants		10.8	8
Depreciation and amortization expense		191.1	193.5
Goodwill impairment		0	24
Accretion of asset retirement obligations		1.3	1.2
Increase (decrease) in redemption value of mandatorily redeemable preferred interests		2.5	(18.5)
Deferred income tax expense (benefit)		73.4	3.1
Equity (earnings) loss of unconsolidated affiliates		12.6	4.8
Distributions of earnings received from unconsolidated affiliates	[1]	2.7
Risk management activities		8.5	4.4
(Gain) loss on sale or disposition of assets	[2]	16.1	0.9
(Gain) loss from financing activities		5.8	(24.7)
Change in contingent considerations		3.3
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		241.2	94.7
Inventories		53.7	62.3
Accounts payable and other liabilities		(196.9)	(115.9)
Net cash provided by operating activities		318.7	241.3
Cash flows from investing activities
Outlays for property, plant and equipment		(144.2)	(190.1)
Outlays for business acquisition, net of cash acquired		(480.8)
Investments in unconsolidated affiliates		(0.5)
Return of capital from unconsolidated affiliates			3.4
Other, net			(1.3)
Net cash used in investing activities		(625.5)	(188)
Debt obligations:
Proceeds from borrowings under credit facilities		995	532
Repayments of credit facilities		(985)	(977)
Proceeds from borrowings under accounts receivable securitization facility		75	5.7
Repayments of accounts receivable securitization facility		(65)	(75)
Redemption of senior notes and term loan		(160)	(330.6)
Proceeds from issuance of common stock		664.8
Proceeds from issuance of preferred stock and warrants			994.1
Costs incurred in connection with financing arrangements		(7.7)	(38.5)
Repurchase of shares and units under compensation plans		(0.5)	(0.2)
Contributions from noncontrolling interests		8.9	6
Distributions to noncontrolling interests		(9.7)	(2.1)
Distributions to Partnership unitholders		(2.8)	(141.7)
Dividends paid to common and preferred shareholders		(199.7)	(51.4)
Payments of distribution equivalent rights			(0.3)
Net cash provided by (used in) financing activities		313.3	(79)
Net change in cash and cash equivalents		6.5	(25.7)
Cash and cash equivalents, beginning of period		73.5	140.2
Cash and cash equivalents, end of period		$ 80	$ 114.5
[1]	During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.
[2]	Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Organization and Operations

Organization and Operations	3 Months Ended
	Mar. 31, 2017
Organization [Abstract]
Organization and Operations	Note 1 — Organization and Operations Our 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. Our Operations The Company is engaged in the business of: • gathering, compressing, treating, processing and selling natural gas; • storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; • gathering, storing and terminaling crude oil; and • storing, terminaling and selling refined petroleum products. See Note 21 – Segment Information for certain financial information regarding our business segments.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [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 months ended March 31, 2017 and 2016 include all adjustments that we believe are necessary for a fair statement 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 months ended March 31, 2017 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”). Prior to February 17, 2016, our interests in the Partnership consisted 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 representing limited partner interests in the Partnership (“common units”), representing an 8.8% 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. On February 17, 2016, we completed the transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transactions, the “TRC/TRP Merger” or “Buy-in Transaction”), dated November 2, 2015, by and among us, the general partner of TRP, TRC and Spartan Merger Sub LLC, a subsidiary of us (“Merger Sub”) and we acquired indirectly all of the outstanding TRP common units that we and our subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by us or our subsidiaries was converted into the right to receive 0.62 shares of our common stock. We issued 104,525,775 shares of our common stock to third-party unitholders of the common units of the Partnership in exchange for all of the 168,590,009 outstanding common units of the Partnership that we previously did not own. No fractional shares were issued in the TRC/TRP Merger, and TRP common unitholders instead received cash in lieu of fractional shares. There were no changes to our other interests in the Partnership. TRP’s 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding after the TRC/TRP Merger. The Preferred Units are listed on the NYSE under “NGLS PRA” and are publicly traded. The Preferred Units are reported as noncontrolling interests in our financial statements. As we continued to control the Partnership after the TRC/TRP Merger, the resulting change in our ownership interest was accounted for as an equity transaction, which is reflected in our Consolidated Balance Sheet as a reduction of noncontrolling interests and a corresponding increase in common stock and additional paid in capital. The TRC/TRP Merger was a taxable exchange that resulted in a book/tax difference in the basis of the underlying assets acquired (our investment in TRP). The tax impact is presented as a reduction of additional paid-in capital consistent with the accounting for tax effects of transactions with noncontrolling interests. The earnings recorded by TRP that were attributed to its common units held by the public prior to February 17, 2016 are reflected within “Net income attributable to noncontrolling interests” in our Consolidated Statements of Operations for periods prior to the merger date. On October 19, 2016, TRP executed the Third Amended and Restated Partnership Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), effective as of December 1, 2016. The Third A&R Partnership Agreement (i) eliminated the IDRs held by the General Partner, and related distribution and allocation provisions, (ii) eliminated the Special GP Interest held by the General Partner, (iii) provided the ability to declare monthly distributions in addition to quarterly distributions, (iv) modified certain provisions relating to distributions from available cash, (v) eliminated the Class B Unit provisions and (vi) made changes to reflect the passage of time and removed provisions that were no longer applicable. In connection with the Third A&R Partnership Agreement, on December 1, 2016, TRP issued to the General Partner (i) 20,380,286 Common Units and 424,590 General Partner Units in exchange for the elimination of the IDRs and (ii) 11,267,485 Common Units and 234,739 General Partner Units in exchange for the elimination of the Special GP Interest.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2017
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 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. There were no significant updates or revisions to our policies during the three months ended March 31, 2017, except as noted below. Recent Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606. Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Recognition of Intra-Entity Transfers of Assets Other than Inventory In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis which resulted in a cumulative effect adjustment on retained earnings as of January 1, 2017 of $56.1 million in order to recognize unamortized tax expense previously deferred of $40.1 million and deferred tax assets previously unrecognized of $96.2 million. We did not have intra-entity transfers of assets other than inventory during the current period. Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Goodwill Impairment In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment Other Income In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendment on our consolidated financial statements.

Business Acquisitions and Dives

Business Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2017
Business Acquisitions And Divestitures [Abstract]
Business Acquisitions and Divestitures	Note 4 – Business Acquisitions and Divestitures 2017 Acquisition Permian Acquisition On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”). We paid $484.1 million in cash at closing on March 1, 2017, and will pay $90.0 million within 90 days of closing (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017. New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations. New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations. New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017 and we expect that New Midland’s gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers. On January 26, 2017, we completed a public offering of 9,200,000 shares of our common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. We used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. The acquired businesses contributed revenues of $8.1 million and a net loss of $1.6 million to us for the period from March 1, 2017 to March 31, 2017, and are reported in our Gathering and Processing segment. As of March 31, 2017, we had incurred $5.1 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the three months ended March 31, 2017. Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. March 31, 2017 March 31, 2016 Pro Forma Pro Forma Revenues $ 2,126.7 $ 1,445.0 Net income (loss) (111.4 ) (12.5 ) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated: • Reflect the amortization expense resulting from the preliminary estimate of the fair value of intangible assets recognized as part of the Permian Acquisition. For the purposes of preparing the pro forma adjustments we have assumed a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations. • Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the preliminary estimate of the fair value of property, plant and equipment acquired. • Exclude $5.1 million of acquisition-related costs incurred as of March 31, 2017 from pro forma net income for the three months ended March 31, 2017. Pro forma net income for the three months ended March 31, 2016 was adjusted to include those charges. • Reflect the income tax effects of the above pro forma adjustments. The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of cash acquired (1) $ 480.8 Purchase consideration payable (2) 90.0 Contingent consideration 461.6 Total $ 1,032.4 (1) Net of cash acquired of $3.3 million. (2) The payable will be settled in cash within 90 days from March 1, 2017. We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the completion of the valuation and other post-closing adjustments. These and other estimates are subject to change as additional information becomes available and is assessed by us, and agreement is reached on the respective final settlement statements. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination: March 1, 2017 Trade and other current receivables, net $ 6.5 Other current assets 0.6 Property, plant and equipment 255.4 Intangible assets 625.6 Current liabilities (14.3 ) Other long-term liabilities (0.4 ) Total identifiable net assets 873.4 Goodwill 159.0 Total fair value of consideration transferred $ 1,032.4 Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill . operational and capital synergies. The preliminary fair value of assets acquired included trade receivables of $6.5 million, all of which was expected to be collectible. The 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 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. During the three months ended March 31, 2017, we recognized $3.2 million as Other expense related to the change in fair value of the contingent consideration. See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology. 2017 Divestiture Sale of Venice Gathering System, L.L.C. Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Venice Gathering System, L.L.C. (“VGS”) a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS. The sale of VGS closed on April 4, 2017, and as a result, we recognized a loss of $16.1 million in our Consolidated Statements of Operations as part of Other operating (income) expense to impair our basis in the VGS assets to its fair value.

Inventories

Inventories	3 Months Ended
	Mar. 31, 2017
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories March 31, 2017 December 31, 2016 Commodities $ 65.1 $ 126.9 Materials and supplies 10.4 10.8 $ 75.5 $ 137.7

Property, Plant and Equipment a

Property, Plant and Equipment and Intangible Assets	3 Months Ended
	Mar. 31, 2017
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	Note 6 — Property, Plant and Equipment and Intangible Assets Property, Plant and Equipment March 31, 2017 December 31, 2016 Estimated Useful Lives (In Years) Gathering systems $ 6,777.7 $ 6,626.8 5 to 20 Processing and fractionation facilities 3,506.9 3,390.2 5 to 25 Terminaling and storage facilities 1,231.7 1,205.0 5 to 25 Transportation assets 427.9 451.4 10 to 25 Other property, plant and equipment 280.6 274.2 3 to 25 Land 121.6 121.3 — Construction in progress 610.6 449.8 — Property, plant and equipment 12,957.0 12,518.7 Accumulated depreciation (2,993.6 ) (2,827.7 ) Property, plant and equipment, net $ 9,963.4 $ 9,691.0 Intangible assets $ 2,662.2 $ 2,036.6 15 to 20 Accumulated amortization (423.4 ) (382.6 ) Intangible assets, net $ 2,238.8 $ 1,654.0 Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012. 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 intangible assets acquired in the Permian Acquisition were recorded at a preliminary fair value of $625.6 million pending completion of final valuations. For the purposes of preparing the accompanying financial statements (which include one month of amortization of these intangible assets), we are amortizing these intangible assets over a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations over the upcoming months. The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. 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 over a 20-year life. The estimated annual amortization expense for intangible assets, including the provisional Permian valuations and straight-line treatment is approximately $184.2 million, $177.4 million, $166.4 million, $154.2 million and $144.3 million for each of the years 2017 through 2021. The changes in our intangible assets are as follows: Balance at December 31, 2016 $ 1,654.0 Additions from Permian Acquisition 625.6 Amortization (40.8 ) Balance at March 31, 2017 $ 2,238.8

Goodwill

Goodwill	3 Months Ended
	Mar. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	Note 7 – Goodwill As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million on our Consolidated Statement of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Changes in the net book value of our goodwill are as follows: WestTX SouthTX Permian Total Balance at December 31, 2016, net $ 174.7 $ 35.3 $ — $ 210.0 Permian Acquisition, March 1, 2017 (preliminary valuation) — — 159.0 159.0 Balance at March 31, 2017, net $ 174.7 $ 35.3 $ 159.0 $ 369.0

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2017
Equity Method Investments And Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Note 8 – Investments in Unconsolidated Affiliates Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with the joint interest owners, which cover their costs of operations (excluding depreciation and amortization). The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments and our share of any operating expenses incurred by the T2 Joint Ventures. The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Total Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ 240.8 Equity earnings (loss) 3.7 (1.1 ) (2.7 ) (12.5 ) (12.6 ) Cash distributions (1) (2.7 ) — — — (2.7 ) Contributions for expansion projects (2) — 0.3 1.1 0.1 1.5 Balance at March 31, 2017 $ 47.1 $ 57.8 $ 117.0 $ 5.1 $ 227.0 (1) During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur. (2) Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford. Our equity loss for the three months ended March 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment has occurred that is other than temporary. As a result of this evaluation, we have recorded an impairment loss of approximately $12.0 million, which represents our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as the impairment of the unamortized excess fair value resulting from the Atlas mergers. The carrying values of the T2 gathering joint ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of March 31, 2017, $30.1 million of unamortized excess fair value over the T2 Joint Ventures capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20 year useful lives of the underlying assets.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	3 Months Ended
	Mar. 31, 2017
Payables And Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 — Accounts Payable and Accrued Liabilities March 31, 2017 December 31, 2016 Commodities $ 512.1 $ 574.4 Other goods and services 122.2 117.0 Purchase consideration payable 90.0 - Interest 52.7 52.3 Compensation and benefits 20.2 37.2 Income and other taxes 22.6 24.2 Preferred Series A dividends payable 22.9 22.9 Other 24.5 15.5 $ 867.2 $ 843.5 Accounts payable and accrued liabilities includes $27.4 million and $30.5 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2017 and December 31, 2016.

Debt Obligations

Debt Obligations	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Debt Obligations	Note 10 — Debt Obligations March 31, 2017 December 31, 2016 Current: Obligations of the Partnership: (1) Accounts receivable securitization facility, due December 2017 $ 285.0 $ 275.0 Senior unsecured notes, 5% fixed rate, due January 2018 250.5 — 535.5 275.0 Debt issuance costs, net of amortization (0.6 ) — Current maturities of debt 534.9 275.0 Long-term: TRC obligations: TRC Senior secured revolving credit facility, variable rate, due February 2020 (2) 435.0 275.0 TRC Senior secured term loan, variable rate, due February 2022 — 160.0 Unamortized discount — (2.2 ) Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due October 2020 (3) — 150.0 Senior unsecured notes: 5% fixed rate, due January 2018 — 250.5 4 ⅛ 749.4 749.4 6 ⅜ 278.7 278.7 5 ¼ 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛ % fixed rate, due February 2025 500.0 500.0 5⅜ % fixed rate, due February 2027 500.0 500.0 TPL notes, 4¾% fixed rate, due November 2021 (4) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (4) 48.1 48.1 Unamortized premium 0.5 0.5 4,241.8 4,640.1 Debt issuance costs, net of amortization (28.5 ) (34.1 ) Long-term debt 4,213.3 4,606.0 Total debt obligations $ 4,748.2 $ 4,881.0 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) 15.8 13.2 $ 15.8 $ 13.2 (1) While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership or Targa Pipeline Partners, L.P. (“TPL”). (2) As of March 31, 2017, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million. (3) As of March 31, 2017, availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million. (4) TPL notes are not guaranteed by us or the Partnership. The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the three months ended March 31, 2017: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRC Revolver 2.5% - 4.5% 2.6% TRC Senior secured term loan (1) 5.75% 5.75% TRP Revolver 3.0% - 5.3% 3.2% Partnership's accounts receivable securitization facility 1.8% 1.8% (1) The TRC Senior secured term loan is a Eurodollar rate loan with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of 4.75%. Compliance with Debt Covenants As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements. Securitization Facility On February 23, 2017, we amended the Partnership’s accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million. As of March 31, 2017, there was $285.0 million outstanding under the Securitization Facility. TRC Revolver On March 14, 2017, the $160.0 million outstanding balance on the TRC Senior secured term loan was repaid using borrowings under the TRC Revolver.

Other Long-term Liabilities

Other Long-term Liabilities	3 Months Ended
	Mar. 31, 2017
Other Liabilities Noncurrent [Abstract]
Other Long-term Liabilities	Note 11 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: March 31, 2017 December 31, 2016 Asset retirement obligations $ 68.0 $ 64.6 Mandatorily redeemable preferred interests 71.9 68.5 Deferred revenue 69.0 69.8 Permian Acquisition contingent consideration 464.8 — Other liabilities 15.2 12.2 Total long-term liabilities $ 688.9 $ 215.1 Asset Retirement Obligations Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows: Balance at December 31, 2016 $ 64.6 Additions (1) 0.4 Change in cash flow estimate 1.7 Accretion expense 1.3 Balance at March 31, 2017 $ 68.0 ___________________________________________________________________________________________________________________ (1) Amount reflects AROs assumed from the Permian Acquisition Mandatorily Redeemable Preferred Interests Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of March 31, 2017. The following table shows the changes attributable to mandatorily redeemable preferred interests: Balance at December 31, 2016 $ 68.5 Income attributable to mandatorily redeemable preferred interests 0.9 Change in estimated redemption value included in interest expense 2.5 Balance at March 31, 2017 $ 71.9 Deferred Revenue We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement Deferred revenue also includes consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030. Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023. The following table shows the components of deferred revenue: March 31, 2017 December 31, 2016 Splitter agreement $ 43.0 $ 43.0 Gas contract amendment 19.3 19.7 Other deferred revenue 6.7 7.1 Total deferred revenue $ 69.0 $ 69.8 The following table shows the changes in deferred revenue: Balance at December 31, 2016 $ 69.8 Additions - Revenue recognized (0.8 ) Balance at March 31, 2017 $ 69.0 Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The first potential earn-out payment would occur in May 2018. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. For the one month ended March 31, 2017, we had an increase in the fair value of this liability of $3.2 million, bringing the Permian Acquisition contingent consideration to $464.8 million as of March 31, 2017. See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology.

Preferred Stock

Preferred Stock	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Preferred Stock	Note 12 – Preferred Stock Preferred Stock and Detachable Warrants In the first quarter of 2016, TRC sold in two tranches to investors in a private placement 965,100 shares of Series A Preferred Stock (“Series A Preferred”) with detachable Series A Warrants exercisable into a maximum of 13,550,004 shares of our common stock and Series B Warrants exercisable into a maximum of 6,533,727 shares of our common stock (collectively the “Warrants”) for an aggregate purchase price of $994.1 million in cash. The Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The Company may elect to pay dividends for any quarter with a paid-in-kind election (“PIK”) through December 31, 2017. Under the PIK election, unpaid dividends would be added to the liquidation preference and a commensurate amount of Series A and Series B Warrants would be issued. We have not made an election to PIK through March 31, 2017. The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock at an exercise price of $20.77, which represented a 10% premium over the ten day volume weighted average price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of the Purchase Agreement underlying the first tranche. If the investors do not elect to convert their Series A Preferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if the VWAP for the ten preceding trading days is greater than 120% of the conversion price. A change of control provision could result in forced redemption, at the option of the investor, if the Series A Preferred could not otherwise remain outstanding or be replaced with a “substantially equivalent security.” The Series A Preferred does not qualify as a liability instrument under ASC 480 – Distinguishing Liabilities from Equity, The detachable Warrants have a seven-year term and were exercisable beginning on September 16, 2016. They were issued in two series: Series A Warrants exercisable into a maximum number of 13,550,004 shares of our common stock with an exercise price of $18.88 and 6,533,727 Series B Warrants with an exercise price of $25.11. The Warrants may be net settled in cash or shares of common stock at the Company’s option. The Warrants qualify as freestanding financial instruments and meet the derivatives accounting scope exception in ASC 815 because they are indexed to our equity and otherwise meet the applicable criteria for equity classification. The portion of proceeds allocated to the Series A and Series B Warrants was recorded as additional paid-in capital. See exercise of the Warrants in Note 13 – Common Stock and Related Matters. Net cash proceeds were allocated on a relative fair value basis to the Series A Preferred, Series A Warrants and Series B Warrants. The $178.1 million discount on the Series A Preferred created by the relative fair value allocation of proceeds, which is not subject to periodic accretion, would be reported as a deemed dividend in the event a redemption occurs. As described below, $614.4 million of the $787.1 million allocated to the Series A Preferred was allocated to additional paid-in capital to give effect to the intrinsic value of a beneficial conversion feature (“BCF”). The following table summarizes the accounting upon issuance of our Series A Preferred: Allocation of Proceeds Additional Paid-in Capital Series A Preferred Series A Warrants Series B Warrants Beneficial Conversion Feature Gross proceeds $ 994.1 Transaction fees (24.8 ) Net Proceeds- Initial Relative Fair Value Allocation $ 969.3 $ 787.1 $ 135.7 $ 46.5 $ — Allocation to BCF (614.4 ) — — 614.4 Per balance sheet upon issuance $ 172.7 $ 135.7 $ 46.5 $ 614.4 Beneficial Conversion Feature ASC 470-20-20 – Debt – Debt with conversion and Other Options We have the right to redeem the Series A Preferred beginning after year five. As such, we can effectively mitigate or limit the Series A Preferred Holders’ ability to benefit from their conversion right after year twelve by paying either a $96.5 million (10%) redemption premium in year six or a $48.3 million (5%) redemption premium in years seven through twelve. In either case, the redemption premium would be significantly less than the $614.4 million BCF required to be recognized under GAAP. Upon exercise of our redemption rights, any previously recognized accretion of deemed dividends would be reversed in the period of redemption and reflected as income attributable to common shareholders in our Consolidated Statement of Operations and related per share amounts. Preferred Stock Dividends As of March 31, 2017, we have accrued cumulative preferred dividends of $22.9 million, which will be paid on May 15, 2017. During the three months ended March 31, 2017, we paid $22.9 million of dividends to preferred shareholders, and recorded deemed dividends of $6.1 million attributable to accretion of the preferred discount resulting from the BCF accounting described above. Such accretion is included in the book value of the Series A Preferred Stock.

Common Stock and Related Matter

Common Stock and Related Matters	3 Months Ended
	Mar. 31, 2017
Class Of Stock Disclosures [Abstract]
Common Stock and Related Matters	Note 13 — Common Stock and Related Matters Public Offerings of Common Stock On January 26, 2017, we completed a public offering of 9,200,000 shares of our common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. We used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. For the three months ended March 31, 2017, we issued 2,686,460 shares of common stock under our Equity Distribution Agreement entered into in December 2016 (the “December 2016 EDA”), receiving net proceeds of $152.8 million, of which $19.6 million was settled in April. As of March 31, 2017 we have $516.5 million remaining under the December 2016 EDA. Warrants During 2016, 19,983,843 warrants were exercised and net settled for 11,336,856 shares of common stock. For the three months ended March 31, 2017, no detachable Warrants were exercised. As a result, Series A Warrants exercisable into a maximum of 67,392 shares of common stock and Series B Warrants exercisable into maximum of 32,496 shares of common stock were outstanding as of March 31, 2017. Dividends The following table details the dividends declared and/or paid by us to common shareholders during the three months ended March 31, 2017. Three Months Ended Date Paid or To Be Paid Total Common Dividends Declared Amount of Common Dividends Paid or To Be Paid Accrued Dividends (1) Dividend Declared per Share of Common Stock ( per share amounts) March 31, 2017 May 16, 2017 $ 182.8 $ 180.3 $ 2.5 $ 0.91000 December 31, 2016 February 15, 2017 178.3 176.5 1.8 0.91000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting. Dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital. Subsequent Event During April 2017, we issued 1,464,408 shares of common stock under the December 2016 EDA, receiving net proceeds of $85.8 million. As of April 30, 2017, we have approximately $430.0 million remaining under the December 2016 EDA.

Partnership Units and Related M

Partnership Units and Related Matters	3 Months Ended
	Mar. 31, 2017
Partners Capital [Abstract]
Partnership Units and Related Matters	Note 14 — Partnership Units and Related Matters Distributions As a result of the TRC/TRP Merger in 2016, we are entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. The Partnership has discretion under the Third A&R Partnership Agreement See Note 2 – Basis of Presentation. The following details the distributions declared or paid by the Partnership during the three months ended March 31, 2017. Three Months Date Paid Total Distributions Targa Ended Or to Be Paid Distributions Corp. March 31, 2017 May 11, 2017 $ 209.6 $ 206.8 December 31, 2016 February 10, 2017 198.1 195.3 Contributions Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions to the Partnership, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. During three months ended March 31, 2017, we made total capital contributions to the Partnership of $655.0 million. Preferred Units In October 2015, the Partnership completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on the Partnership’s Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership’s general partner. Distributions on the Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. The Partnership paid $2.8 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three months ended March 31, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements. Subsequent Event In April 2017, the board of directors of the general partner of the Partnership declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions which will be paid on May 15, 2017.

Earnings per Common Share

Earnings per Common Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings per Common Share	Note 15 — Earnings per Common Share The following table sets forth a reconciliation of net income and weighted average shares outstanding (in millions) used in computing basic and diluted net income per common share: Three Months Ended March 31, 2017 2016 Net income $ (110.5 ) $ (0.7 ) Less: Net income attributable to noncontrolling interests 8.8 2.0 Less: Dividends on preferred stock 29.0 3.8 Net income attributable to common shareholders for basic earnings per share $ (148.3 ) $ (6.5 ) Weighted average shares outstanding - basic 191.8 106.6 Net income available per common share - basic $ (0.77 ) $ (0.06 ) Weighted average shares outstanding 191.8 106.6 Dilutive effect of unvested stock awards — — Weighted average shares outstanding - diluted 191.8 106.6 Net income available per common share - diluted $ (0.77 ) $ (0.06 ) The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis): Three Months Ended March 31, 2017 2016 Unvested restricted stock awards 1.3 0.1 Warrants to purchase common stock 0.1 2.0 Series A preferred stock (1) 46.5 13.8 (1) The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock. See Note 12 – Preferred Stock.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 16 — Derivative Instruments and Hedging Activities The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes. The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our 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 our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations. We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes. As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. 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. Additionally, we recorded ineffectiveness losses of less than $0.1 million for the three months ended March 31, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the three months ended March 31, 2017. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues. At March 31, 2017, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 Natural Gas Swaps MMBtu/d 141,960 100,500 61,383 Natural Gas Basis Swaps MMBtu/d 95,963 1,103 - Natural Gas Futures MMBtu/d - 1,103 - Natural Gas Options MMBtu/d 22,900 9,486 - NGL Swaps Bbl/d 14,143 6,658 5,339 NGL Futures Bbl/d 5,702 1,288 - NGL Options Bbl/d 1,647 1,676 - Condensate Swaps Bbl/d 2,690 2,190 1,063 Condensate Options Bbl/d 1,380 691 590 Our derivative contracts are subject to netting arrangements that permit our 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 March 31, 2017 Fair Value as of December 31, 2016 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 23.6 $ 20.8 $ 16.7 $ 48.6 Long-term 21.6 7.9 5.1 26.1 Total derivatives designated as hedging instruments $ 45.2 $ 28.7 $ 21.8 $ 74.7 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.3 $ 1.4 $ 0.1 $ 0.5 Total derivatives not designated as hedging instruments $ 0.3 $ 1.4 $ 0.1 $ 0.5 Total current position $ 23.9 $ 22.2 $ 16.8 $ 49.1 Total long-term position 21.6 7.9 5.1 26.1 Total derivatives $ 45.5 $ 30.1 $ 21.9 $ 75.2 The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation March 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 23.8 $ (20.8 ) $ 0.1 $ 10.8 $ (7.7 ) Counterparties without offsetting positions - assets 0.1 - - 0.1 - Counterparties without offsetting positions - liabilities - (1.4 ) - - (1.4 ) 23.9 (22.2 ) 0.1 10.9 (9.1 ) Long Term Position Counterparties with offsetting positions or collateral 21.3 (6.6 ) - 16.7 (2.0 ) Counterparties without offsetting positions - assets 0.3 - - 0.3 - Counterparties without offsetting positions - liabilities - (1.3 ) - - (1.3 ) 21.6 (7.9 ) - 17.0 (3.3 ) Total Derivatives Counterparties with offsetting positions or collateral 45.1 (27.4 ) 0.1 27.5 (9.7 ) Counterparties without offsetting positions - assets 0.4 - - 0.4 - Counterparties without offsetting positions - liabilities - (2.7 ) - - (2.7 ) $ 45.5 $ (30.1 ) $ 0.1 $ 27.9 $ (12.4 ) Gross Presentation Pro forma net presentation December 31, 2016 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 16.8 $ (46.1 ) $ 7.0 $ 5.7 $ (28.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.0 ) - - (3.0 ) 16.8 (49.1 ) 7.0 5.7 (31.0 ) Long Term Position Counterparties with offsetting positions or collateral 5.1 (18.7 ) - - (13.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.4 ) - - (7.4 ) 5.1 (26.1 ) - - (21.0 ) Total Derivatives Counterparties with offsetting positions or collateral 21.9 (64.8 ) 7.0 5.7 (41.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (10.4 ) - - (10.4 ) $ 21.9 $ (75.2 ) $ 7.0 $ 5.7 $ (52.0 ) Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $15.4 million as of March 31, 2017. 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. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment. The following tables reflect amounts recorded in Other Comprehensive Income 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 Three Months Ended March 31, Hedging Relationships 2017 2016 Commodity contracts $ 66.2 $ 6.7 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended March 31, Location of Gain (Loss) 2017 2016 Revenues $ (6.1 ) $ 24.2 Our consolidated earnings are also affected by the 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. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended March 31, as Hedging Instruments Derivatives 2017 2016 Commodity contracts Revenue $ (0.8 ) $ 1.8 Based on valuations as of March 31, 2017, we expect to reclassify commodity hedge related deferred gains of $10.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $2.6 million of losses to be reclassified over the next twelve months. See Note 17 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 17 — 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 Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold. The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2017, a net asset position of $15.4 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $47.5 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 $79.0 million, ignoring an adjustment for counterparty credit risk. Fair Value of Other Financial Instruments Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: • The TRC Revolver, TRP Revolver, and the Partnership’s accounts receivable securitization facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and • Our term loan and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt. Contingent consideration liabilities related to business acquisitions are carried at fair value. Fair Value Hierarchy We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date 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: March 31, 2017 Carrying Fair Value 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) $ 37.7 $ 37.7 $ — $ 35.7 $ 2.0 Liabilities from commodity derivative contracts (1) 22.1 22.1 — 20.8 1.3 Permian Acquisition contingent consideration (2) 464.8 464.8 — — 464.8 TPL contingent consideration (3) 2.7 2.7 — — 2.7 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 80.0 80.0 — — — TRC Revolver 435.0 435.0 — 435.0 — TRC term loan — — — — — TRP Revolver — — — — — Partnership's Senior unsecured notes 4,057.3 4,169.1 — 4,169.1 — Partnership's accounts receivable securitization facility 285.0 285.0 — 285.0 — December 31, 2016 Carrying Fair Value 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) $ 21.0 $ 21.0 $ — $ 19.6 $ 1.4 Liabilities from commodity derivative contracts (1) 74.2 74.2 — 69.3 4.9 TPL contingent consideration (3) 2.6 2.6 — — 2.6 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 73.5 73.5 — — — TRC Revolver 275.0 275.0 — 275.0 — TRC term loan 157.8 158.4 — 158.4 — TRP Revolver 150.0 150.0 — 150.0 — Partnership's Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — Partnership's accounts receivable securitization facility 275.0 275.0 — 275.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 16 – 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) We have a contingent consideration liability related to the Permian Acquisition. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value. Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or 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 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 March 31, 2017, we had 17 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial. The fair value of the Permian Acquisition contingent consideration was determined using a Monte-Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) on the Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2016 $ (3.6 ) $ (2.6 ) Change in fair value of TPL contingent consideration - (0.1 ) Fair value of Permian Acquisition contingent consideration (1) - (464.8 ) New Level 3 derivative instruments (0.1 ) - Transfers out of Level 3 (2) 1.6 - Settlements included in Revenue 0.2 - Unrealized gain/(loss) included in OCI 2.6 - Balance, March 31, 2017 $ 0.7 $ (467.5 ) (1) Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value. (2) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2017
Loss Contingency [Abstract]
Contingencies	Note 18 – Contingencies Legal Proceedings Environmental Proceedings On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A. Inc. On January 31, 2017, Targa Midstream Services LLC executed a settlement agreement with the New Mexico Environment Department which resolved the matter for a civil penalty in the amount of $29,223. We and the Partnership are also parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business

Other Operating (Income) Expens

Other Operating (Income) Expense	3 Months Ended
	Mar. 31, 2017
Other Income And Expenses [Abstract]
Other Operating (Income) Expense	Note 19 – Other Operating (Income) Expense Other operating (income) expense is comprised of the following: Three Months Ended March 31, 2017 2016 (Gain) loss on sale or disposal of assets (1) $ 16.1 $ 0.9 Miscellaneous business tax 0.1 0.1 $ 16.2 $ 1.0 (1) Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 20 - Supplemental Cash Flow Information Three Months Ended March 31, 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 56.1 $ 82.8 Income taxes paid, net of refunds (0.2 ) 1.0 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 8.3 $ 16.9 Impact of capital expenditure accruals on property, plant and equipment 30.0 13.7 Transfers from materials and supplies inventory to property, plant and equipment 0.4 0.5 Contribution of property, plant and equipment to investment in unconsolidated affiliates. 1.0 — Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.7 (9.1 ) Non-cash financing activities: Reduction of Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements $ 2.2 $ 3.7 Accrued issue costs associated with Series A preferred stock — 3.3 Receivables from equity offerings 19.6 — Impact of accounting standard adoption recorded in retained earnings 56.1 — Change in accrued dividends of Series A Preferred Stock — 3.8 Accrued deemed dividends of Series A Preferred Stock 6.1 — Non-cash balance sheet movements related to the Permian Acquisition: Contingent consideration recorded at the acquisition date $ 461.6 $ — Purchase consideration payable recorded for the Permian Acquisition 90.0 — Non-cash balance sheet movements related to the TRC/TRP Merger: Prepaid transaction costs reclassified in the additional paid-in capital — 4.5 Issuance of common stock — 0.1 Additional paid-in capital — 3,115.5 Accumulated other comprehensive income — 55.9 Noncontrolling interests — (4,119.9 ) Deferred tax liability — 948.4 (1) Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 21 — Segment Information We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Our Gathering and Processing segment 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 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; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment 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, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs. Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas; Lake Charles, Louisiana and Tacoma, Washington. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables: Three Months Ended March 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 166.7 $ 1,692.4 $ (1.0 ) $ — $ 1,858.1 Fees from midstream services 118.2 136.3 — — 254.5 284.9 1,828.7 (1.0 ) — 2,112.6 Intersegment revenues Sales of commodities 713.0 75.4 — (788.4 ) — Fees from midstream services 1.9 7.0 — (8.9 ) — 714.9 82.4 — (797.3 ) — Revenues $ 999.8 $ 1,911.1 $ (1.0 ) $ (797.3 ) $ 2,112.6 Operating margin $ 177.4 $ 130.1 $ (1.0 ) $ — $ 306.5 Other financial information: Total assets (1) $ 10,780.4 $ 2,687.2 $ 44.9 $ 141.3 $ 13,653.8 Goodwill $ 369.0 $ — $ — $ — $ 369.0 Capital expenditures $ 139.2 $ 34.6 $ — $ 0.8 $ 174.6 (1) Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. Three Months Ended March 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 110.3 $ 1,033.9 $ 26.8 $ — $ 1,171.0 Fees from midstream services 115.8 155.6 — — 271.4 226.1 1,189.5 26.8 — 1,442.4 Intersegment revenues Sales of commodities 412.6 47.3 — (459.9 ) — Fees from midstream services 2.1 4.1 — (6.2 ) — 414.7 51.4 — (466.1 ) — Revenues $ 640.8 $ 1,240.9 $ 26.8 $ (466.1 ) $ 1,442.4 Operating margin $ 115.6 $ 157.0 $ 26.8 $ (0.1 ) $ 299.3 Other financial information: Total assets (1) $ 10,219.0 $ 2,501.0 $ 105.7 $ 123.5 $ 12,949.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 103.0 $ 73.1 $ — $ 0.8 $ 176.9 (1) Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2017 2016 Sales of commodities: Natural gas $ 480.9 $ 326.9 NGL 1,314.9 785.8 Condensate 43.6 22.2 Petroleum products 19.8 9.6 Derivative activities (1.1 ) 26.5 1,858.1 1,171.0 Fees from midstream services: Fractionating and treating 31.0 30.2 Storage, terminaling, transportation and export 99.7 118.4 Gathering and processing 107.7 105.0 Other 16.1 17.8 254.5 271.4 Total revenues $ 2,112.6 $ 1,442.4 The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: Three Months Ended March 31, 2017 2016 Reconciliation of operating margin to net income (loss): Operating margin $ 306.5 $ 299.3 Depreciation and amortization expenses (191.1 ) (193.5 ) General and administrative expenses (48.7 ) (45.3 ) Goodwill impairment - (24.0 ) Interest expense, net (63.0 ) (52.9 ) Other, net (43.1 ) 18.8 Income tax (expense) benefit (71.1 ) (3.1 ) Net income (loss) $ (110.5 ) $ (0.7 )

Significant Accounting Polici29

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Recent Accounting Pronouncements	Recent Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606. Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Recognition of Intra-Entity Transfers of Assets Other than Inventory In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis which resulted in a cumulative effect adjustment on retained earnings as of January 1, 2017 of $56.1 million in order to recognize unamortized tax expense previously deferred of $40.1 million and deferred tax assets previously unrecognized of $96.2 million. We did not have intra-entity transfers of assets other than inventory during the current period. Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Goodwill Impairment In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment Other Income In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendment on our consolidated financial statements.

Business Acquisitions and Div30

Business Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2017
Business Acquisitions And Divestitures [Abstract]
Pro Forma Consolidated Information of Operations	The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. March 31, 2017 March 31, 2016 Pro Forma Pro Forma Revenues $ 2,126.7 $ 1,445.0 Net income (loss) (111.4 ) (12.5 )
Consideration Transferred to Acquire Permian Delaware Assets and Permian Midland Assets	The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of cash acquired (1) $ 480.8 Purchase consideration payable (2) 90.0 Contingent consideration 461.6 Total $ 1,032.4 (1) Net of cash acquired of $3.3 million. (2) The payable will be settled in cash within 90 days from March 1, 2017.
Fair Value of the Assets and Liabilities Assumed at Acquisition Date	We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the completion of the valuation and other post-closing adjustments. These and other estimates are subject to change as additional information becomes available and is assessed by us, and agreement is reached on the respective final settlement statements. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination: March 1, 2017 Trade and other current receivables, net $ 6.5 Other current assets 0.6 Property, plant and equipment 255.4 Intangible assets 625.6 Current liabilities (14.3 ) Other long-term liabilities (0.4 ) Total identifiable net assets 873.4 Goodwill 159.0 Total fair value of consideration transferred $ 1,032.4

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Mar. 31, 2017
Inventory Disclosure [Abstract]
Components of Inventories	March 31, 2017 December 31, 2016 Commodities $ 65.1 $ 126.9 Materials and supplies 10.4 10.8 $ 75.5 $ 137.7

Property, Plant and Equipment32

Property, Plant and Equipment and Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2017
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment March 31, 2017 December 31, 2016 Estimated Useful Lives (In Years) Gathering systems $ 6,777.7 $ 6,626.8 5 to 20 Processing and fractionation facilities 3,506.9 3,390.2 5 to 25 Terminaling and storage facilities 1,231.7 1,205.0 5 to 25 Transportation assets 427.9 451.4 10 to 25 Other property, plant and equipment 280.6 274.2 3 to 25 Land 121.6 121.3 — Construction in progress 610.6 449.8 — Property, plant and equipment 12,957.0 12,518.7 Accumulated depreciation (2,993.6 ) (2,827.7 ) Property, plant and equipment, net $ 9,963.4 $ 9,691.0 Intangible assets $ 2,662.2 $ 2,036.6 15 to 20 Accumulated amortization (423.4 ) (382.6 ) Intangible assets, net $ 2,238.8 $ 1,654.0
Schedule of Changes in Intangible Assets	The changes in our intangible assets are as follows: Balance at December 31, 2016 $ 1,654.0 Additions from Permian Acquisition 625.6 Amortization (40.8 ) Balance at March 31, 2017 $ 2,238.8

Goodwill (Tables)

Goodwill (Tables)	3 Months Ended
	Mar. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Changes in Net Book Value of Goodwill	Changes in the net book value of our goodwill are as follows: WestTX SouthTX Permian Total Balance at December 31, 2016, net $ 174.7 $ 35.3 $ — $ 210.0 Permian Acquisition, March 1, 2017 (preliminary valuation) — — 159.0 159.0 Balance at March 31, 2017, net $ 174.7 $ 35.3 $ 159.0 $ 369.0

Investments in Unconsolidated34

Investments in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2017
Equity Method Investments And Joint Ventures [Abstract]
Activity Related to Partnership's Investments in Unconsolidated Affiliates	The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Total Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ 240.8 Equity earnings (loss) 3.7 (1.1 ) (2.7 ) (12.5 ) (12.6 ) Cash distributions (1) (2.7 ) — — — (2.7 ) Contributions for expansion projects (2) — 0.3 1.1 0.1 1.5 Balance at March 31, 2017 $ 47.1 $ 57.8 $ 117.0 $ 5.1 $ 227.0 (1) During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur. (2) Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

Accounts Payable and Accrued 35

Accounts Payable and Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2017
Payables And Accruals [Abstract]
Schedule of Accounts Payable and Accrued Liabilities	March 31, 2017 December 31, 2016 Commodities $ 512.1 $ 574.4 Other goods and services 122.2 117.0 Purchase consideration payable 90.0 - Interest 52.7 52.3 Compensation and benefits 20.2 37.2 Income and other taxes 22.6 24.2 Preferred Series A dividends payable 22.9 22.9 Other 24.5 15.5 $ 867.2 $ 843.5

Debt Obligations (Tables)

Debt Obligations (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Schedule of Outstanding Debt	March 31, 2017 December 31, 2016 Current: Obligations of the Partnership: (1) Accounts receivable securitization facility, due December 2017 $ 285.0 $ 275.0 Senior unsecured notes, 5% fixed rate, due January 2018 250.5 — 535.5 275.0 Debt issuance costs, net of amortization (0.6 ) — Current maturities of debt 534.9 275.0 Long-term: TRC obligations: TRC Senior secured revolving credit facility, variable rate, due February 2020 (2) 435.0 275.0 TRC Senior secured term loan, variable rate, due February 2022 — 160.0 Unamortized discount — (2.2 ) Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due October 2020 (3) — 150.0 Senior unsecured notes: 5% fixed rate, due January 2018 — 250.5 4 ⅛ 749.4 749.4 6 ⅜ 278.7 278.7 5 ¼ 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛ % fixed rate, due February 2025 500.0 500.0 5⅜ % fixed rate, due February 2027 500.0 500.0 TPL notes, 4¾% fixed rate, due November 2021 (4) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (4) 48.1 48.1 Unamortized premium 0.5 0.5 4,241.8 4,640.1 Debt issuance costs, net of amortization (28.5 ) (34.1 ) Long-term debt 4,213.3 4,606.0 Total debt obligations $ 4,748.2 $ 4,881.0 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) 15.8 13.2 $ 15.8 $ 13.2 (1) While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership or Targa Pipeline Partners, L.P. (“TPL”). (2) As of March 31, 2017, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million. (3) As of March 31, 2017, availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million. (4) TPL notes are not guaranteed by us or the Partnership.
Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations	The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the three months ended March 31, 2017: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRC Revolver 2.5% - 4.5% 2.6% TRC Senior secured term loan (1) 5.75% 5.75% TRP Revolver 3.0% - 5.3% 3.2% Partnership's accounts receivable securitization facility 1.8% 1.8% (1) The TRC Senior secured term loan is a Eurodollar rate loan with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of 4.75%.

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	3 Months Ended
	Mar. 31, 2017
Other Liabilities Noncurrent [Abstract]
Schedule of Other Long-term Liabilities	Other long-term liabilities are comprised of the following obligations: March 31, 2017 December 31, 2016 Asset retirement obligations $ 68.0 $ 64.6 Mandatorily redeemable preferred interests 71.9 68.5 Deferred revenue 69.0 69.8 Permian Acquisition contingent consideration 464.8 — Other liabilities 15.2 12.2 Total long-term liabilities $ 688.9 $ 215.1
Changes in Aggregate ARO	The changes in our ARO are as follows: Balance at December 31, 2016 $ 64.6 Additions (1) 0.4 Change in cash flow estimate 1.7 Accretion expense 1.3 Balance at March 31, 2017 $ 68.0 ___________________________________________________________________________________________________________________ (1) Amount reflects AROs assumed from the Permian Acquisition
Schedule of Changes Attributable to Mandatorily Redeemable Preferred Interests	The following table shows the changes attributable to mandatorily redeemable preferred interests: Balance at December 31, 2016 $ 68.5 Income attributable to mandatorily redeemable preferred interests 0.9 Change in estimated redemption value included in interest expense 2.5 Balance at March 31, 2017 $ 71.9
Components of deferred revenue	The following table shows the components of deferred revenue: March 31, 2017 December 31, 2016 Splitter agreement $ 43.0 $ 43.0 Gas contract amendment 19.3 19.7 Other deferred revenue 6.7 7.1 Total deferred revenue $ 69.0 $ 69.8
Changes In Deferred revenue	The following table shows the changes in deferred revenue: Balance at December 31, 2016 $ 69.8 Additions - Revenue recognized (0.8 ) Balance at March 31, 2017 $ 69.0

Preferred Stock (Tables)

Preferred Stock (Tables)	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Accounting for Series A preferred stock	The following table summarizes the accounting upon issuance of our Series A Preferred: Allocation of Proceeds Additional Paid-in Capital Series A Preferred Series A Warrants Series B Warrants Beneficial Conversion Feature Gross proceeds $ 994.1 Transaction fees (24.8 ) Net Proceeds- Initial Relative Fair Value Allocation $ 969.3 $ 787.1 $ 135.7 $ 46.5 $ — Allocation to BCF (614.4 ) — — 614.4 Per balance sheet upon issuance $ 172.7 $ 135.7 $ 46.5 $ 614.4

Common Stock and Related Matt39

Common Stock and Related Matters (Tables)	3 Months Ended
	Mar. 31, 2017
Class Of Stock Disclosures [Abstract]
Dividends Declared and/or Paid	The following table details the dividends declared and/or paid by us to common shareholders during the three months ended March 31, 2017. Three Months Ended Date Paid or To Be Paid Total Common Dividends Declared Amount of Common Dividends Paid or To Be Paid Accrued Dividends (1) Dividend Declared per Share of Common Stock ( per share amounts) March 31, 2017 May 16, 2017 $ 182.8 $ 180.3 $ 2.5 $ 0.91000 December 31, 2016 February 15, 2017 178.3 176.5 1.8 0.91000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Partnership Units and Related40

Partnership Units and Related Matters (Tables)	3 Months Ended
	Mar. 31, 2017
Partners Capital [Abstract]
Schedule of Distributions	The following details the distributions declared or paid by the Partnership during the three months ended March 31, 2017. Three Months Date Paid Total Distributions Targa Ended Or to Be Paid Distributions Corp. March 31, 2017 May 11, 2017 $ 209.6 $ 206.8 December 31, 2016 February 10, 2017 198.1 195.3

Earnings per Common Share (Tabl

Earnings per Common Share (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Reconciliation of Net Income and Weighted Average Shares Outstanding Used in Computing Basic and Diluted Net Income Per Common Share	The following table sets forth a reconciliation of net income and weighted average shares outstanding (in millions) used in computing basic and diluted net income per common share: Three Months Ended March 31, 2017 2016 Net income $ (110.5 ) $ (0.7 ) Less: Net income attributable to noncontrolling interests 8.8 2.0 Less: Dividends on preferred stock 29.0 3.8 Net income attributable to common shareholders for basic earnings per share $ (148.3 ) $ (6.5 ) Weighted average shares outstanding - basic 191.8 106.6 Net income available per common share - basic $ (0.77 ) $ (0.06 ) Weighted average shares outstanding 191.8 106.6 Dilutive effect of unvested stock awards — — Weighted average shares outstanding - diluted 191.8 106.6 Net income available per common share - diluted $ (0.77 ) $ (0.06 )
Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share	The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis): Three Months Ended March 31, 2017 2016 Unvested restricted stock awards 1.3 0.1 Warrants to purchase common stock 0.1 2.0 Series A preferred stock (1) 46.5 13.8 The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock. See Note 12 – Preferred Stock

Derivative Instruments and He42

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Notional Volume of Commodity Hedges	At March 31, 2017, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 Natural Gas Swaps MMBtu/d 141,960 100,500 61,383 Natural Gas Basis Swaps MMBtu/d 95,963 1,103 - Natural Gas Futures MMBtu/d - 1,103 - Natural Gas Options MMBtu/d 22,900 9,486 - NGL Swaps Bbl/d 14,143 6,658 5,339 NGL Futures Bbl/d 5,702 1,288 - NGL Options Bbl/d 1,647 1,676 - Condensate Swaps Bbl/d 2,690 2,190 1,063 Condensate Options Bbl/d 1,380 691 590
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 March 31, 2017 Fair Value as of December 31, 2016 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 23.6 $ 20.8 $ 16.7 $ 48.6 Long-term 21.6 7.9 5.1 26.1 Total derivatives designated as hedging instruments $ 45.2 $ 28.7 $ 21.8 $ 74.7 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.3 $ 1.4 $ 0.1 $ 0.5 Total derivatives not designated as hedging instruments $ 0.3 $ 1.4 $ 0.1 $ 0.5 Total current position $ 23.9 $ 22.2 $ 16.8 $ 49.1 Total long-term position 21.6 7.9 5.1 26.1 Total derivatives $ 45.5 $ 30.1 $ 21.9 $ 75.2
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet	The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation March 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 23.8 $ (20.8 ) $ 0.1 $ 10.8 $ (7.7 ) Counterparties without offsetting positions - assets 0.1 - - 0.1 - Counterparties without offsetting positions - liabilities - (1.4 ) - - (1.4 ) 23.9 (22.2 ) 0.1 10.9 (9.1 ) Long Term Position Counterparties with offsetting positions or collateral 21.3 (6.6 ) - 16.7 (2.0 ) Counterparties without offsetting positions - assets 0.3 - - 0.3 - Counterparties without offsetting positions - liabilities - (1.3 ) - - (1.3 ) 21.6 (7.9 ) - 17.0 (3.3 ) Total Derivatives Counterparties with offsetting positions or collateral 45.1 (27.4 ) 0.1 27.5 (9.7 ) Counterparties without offsetting positions - assets 0.4 - - 0.4 - Counterparties without offsetting positions - liabilities - (2.7 ) - - (2.7 ) $ 45.5 $ (30.1 ) $ 0.1 $ 27.9 $ (12.4 ) Gross Presentation Pro forma net presentation December 31, 2016 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 16.8 $ (46.1 ) $ 7.0 $ 5.7 $ (28.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.0 ) - - (3.0 ) 16.8 (49.1 ) 7.0 5.7 (31.0 ) Long Term Position Counterparties with offsetting positions or collateral 5.1 (18.7 ) - - (13.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.4 ) - - (7.4 ) 5.1 (26.1 ) - - (21.0 ) Total Derivatives Counterparties with offsetting positions or collateral 21.9 (64.8 ) 7.0 5.7 (41.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (10.4 ) - - (10.4 ) $ 21.9 $ (75.2 ) $ 7.0 $ 5.7 $ (52.0 )
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue and Expense	The following tables reflect amounts recorded in Other Comprehensive Income 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 Three Months Ended March 31, Hedging Relationships 2017 2016 Commodity contracts $ 66.2 $ 6.7 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended March 31, Location of Gain (Loss) 2017 2016 Revenues $ (6.1 ) $ 24.2
Gain (Loss) Recognized in Income on Derivatives	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. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended March 31, as Hedging Instruments Derivatives 2017 2016 Commodity contracts Revenue $ (0.8 ) $ 1.8

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [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: March 31, 2017 Carrying Fair Value 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) $ 37.7 $ 37.7 $ — $ 35.7 $ 2.0 Liabilities from commodity derivative contracts (1) 22.1 22.1 — 20.8 1.3 Permian Acquisition contingent consideration (2) 464.8 464.8 — — 464.8 TPL contingent consideration (3) 2.7 2.7 — — 2.7 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 80.0 80.0 — — — TRC Revolver 435.0 435.0 — 435.0 — TRC term loan — — — — — TRP Revolver — — — — — Partnership's Senior unsecured notes 4,057.3 4,169.1 — 4,169.1 — Partnership's accounts receivable securitization facility 285.0 285.0 — 285.0 — December 31, 2016 Carrying Fair Value 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) $ 21.0 $ 21.0 $ — $ 19.6 $ 1.4 Liabilities from commodity derivative contracts (1) 74.2 74.2 — 69.3 4.9 TPL contingent consideration (3) 2.6 2.6 — — 2.6 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 73.5 73.5 — — — TRC Revolver 275.0 275.0 — 275.0 — TRC term loan 157.8 158.4 — 158.4 — TRP Revolver 150.0 150.0 — 150.0 — Partnership's Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — Partnership's accounts receivable securitization facility 275.0 275.0 — 275.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 16 – 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) We have a contingent consideration liability related to the Permian Acquisition. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.
Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3	The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2016 $ (3.6 ) $ (2.6 ) Change in fair value of TPL contingent consideration - (0.1 ) Fair value of Permian Acquisition contingent consideration (1) - (464.8 ) New Level 3 derivative instruments (0.1 ) - Transfers out of Level 3 (2) 1.6 - Settlements included in Revenue 0.2 - Unrealized gain/(loss) included in OCI 2.6 - Balance, March 31, 2017 $ 0.7 $ (467.5 ) (1) Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value. (2) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

Other Operating (Income) Expe44

Other Operating (Income) Expense (Tables)	3 Months Ended
	Mar. 31, 2017
Other Income And Expenses [Abstract]
Other Operating (Income) Expense	Other operating (income) expense is comprised of the following: Three Months Ended March 31, 2017 2016 (Gain) loss on sale or disposal of assets (1) $ 16.1 $ 0.9 Miscellaneous business tax 0.1 0.1 $ 16.2 $ 1.0 (1) Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Supplemental Cash Flow Inform45

Supplemental Cash Flow Information (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Three Months Ended March 31, 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 56.1 $ 82.8 Income taxes paid, net of refunds (0.2 ) 1.0 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 8.3 $ 16.9 Impact of capital expenditure accruals on property, plant and equipment 30.0 13.7 Transfers from materials and supplies inventory to property, plant and equipment 0.4 0.5 Contribution of property, plant and equipment to investment in unconsolidated affiliates. 1.0 — Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.7 (9.1 ) Non-cash financing activities: Reduction of Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements $ 2.2 $ 3.7 Accrued issue costs associated with Series A preferred stock — 3.3 Receivables from equity offerings 19.6 — Impact of accounting standard adoption recorded in retained earnings 56.1 — Change in accrued dividends of Series A Preferred Stock — 3.8 Accrued deemed dividends of Series A Preferred Stock 6.1 — Non-cash balance sheet movements related to the Permian Acquisition: Contingent consideration recorded at the acquisition date $ 461.6 $ — Purchase consideration payable recorded for the Permian Acquisition 90.0 — Non-cash balance sheet movements related to the TRC/TRP Merger: Prepaid transaction costs reclassified in the additional paid-in capital — 4.5 Issuance of common stock — 0.1 Additional paid-in capital — 3,115.5 Accumulated other comprehensive income — 55.9 Noncontrolling interests — (4,119.9 ) Deferred tax liability — 948.4 (1) Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Reportable Segment Information	Reportable segment information is shown in the following tables: Three Months Ended March 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 166.7 $ 1,692.4 $ (1.0 ) $ — $ 1,858.1 Fees from midstream services 118.2 136.3 — — 254.5 284.9 1,828.7 (1.0 ) — 2,112.6 Intersegment revenues Sales of commodities 713.0 75.4 — (788.4 ) — Fees from midstream services 1.9 7.0 — (8.9 ) — 714.9 82.4 — (797.3 ) — Revenues $ 999.8 $ 1,911.1 $ (1.0 ) $ (797.3 ) $ 2,112.6 Operating margin $ 177.4 $ 130.1 $ (1.0 ) $ — $ 306.5 Other financial information: Total assets (1) $ 10,780.4 $ 2,687.2 $ 44.9 $ 141.3 $ 13,653.8 Goodwill $ 369.0 $ — $ — $ — $ 369.0 Capital expenditures $ 139.2 $ 34.6 $ — $ 0.8 $ 174.6 (1) Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. Three Months Ended March 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 110.3 $ 1,033.9 $ 26.8 $ — $ 1,171.0 Fees from midstream services 115.8 155.6 — — 271.4 226.1 1,189.5 26.8 — 1,442.4 Intersegment revenues Sales of commodities 412.6 47.3 — (459.9 ) — Fees from midstream services 2.1 4.1 — (6.2 ) — 414.7 51.4 — (466.1 ) — Revenues $ 640.8 $ 1,240.9 $ 26.8 $ (466.1 ) $ 1,442.4 Operating margin $ 115.6 $ 157.0 $ 26.8 $ (0.1 ) $ 299.3 Other financial information: Total assets (1) $ 10,219.0 $ 2,501.0 $ 105.7 $ 123.5 $ 12,949.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 103.0 $ 73.1 $ — $ 0.8 $ 176.9 (1) Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
Revenues by Product and Service	The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2017 2016 Sales of commodities: Natural gas $ 480.9 $ 326.9 NGL 1,314.9 785.8 Condensate 43.6 22.2 Petroleum products 19.8 9.6 Derivative activities (1.1 ) 26.5 1,858.1 1,171.0 Fees from midstream services: Fractionating and treating 31.0 30.2 Storage, terminaling, transportation and export 99.7 118.4 Gathering and processing 107.7 105.0 Other 16.1 17.8 254.5 271.4 Total revenues $ 2,112.6 $ 1,442.4
Reconciliation of Operating Margin to Net Income (Loss)	The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: Three Months Ended March 31, 2017 2016 Reconciliation of operating margin to net income (loss): Operating margin $ 306.5 $ 299.3 Depreciation and amortization expenses (191.1 ) (193.5 ) General and administrative expenses (48.7 ) (45.3 ) Goodwill impairment - (24.0 ) Interest expense, net (63.0 ) (52.9 ) Other, net (43.1 ) 18.8 Income tax (expense) benefit (71.1 ) (3.1 ) Net income (loss) $ (110.5 ) $ (0.7 )

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details)	Feb. 17, 2016shares	Mar. 31, 2017shares	Dec. 01, 2016shares
Business Acquisition [Line Items]
Ownership interest in Partnership by general partner		2.00%
Parent's ownership interest in the general partner of the Partnership		100.00%
Number of Partnership common units owned (in units)		16,309,594
Ownership interest in Partnership by limited partner		8.80%
Conversion ratio in stock-for-unit transaction	0.62
Number of shares issued in exchange of common units for common shares to the third party (in shares)	104,525,775
IDRs [Member] | Common Units [Member]
Business Acquisition [Line Items]
Issuance of common units (in units)			20,380,286
IDRs [Member] | General Partner Units [Member]
Business Acquisition [Line Items]
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest			424,590
Special GP Interest [Member] | Common Units [Member]
Business Acquisition [Line Items]
Issuance of common units (in units)			11,267,485
Special GP Interest [Member] | General Partner Units [Member]
Business Acquisition [Line Items]
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest			234,739
Series A Cumulative Redeemable Perpetual Preferred Units [Member]
Business Acquisition [Line Items]
Preferred units, outstanding		5,000,000
Preferred units dividend percentage		9.00%
Targa Resources Partners LP [Member]
Business Acquisition [Line Items]
Number of shares exchanged in exchange of common units for common shares to the third party (in shares)	168,590,009

Significant Accounting Polici48

Significant Accounting Policies (Details) - New Accounting Pronouncement, Early Adoption, Effect [Member] $ in Millions	Jan. 02, 2017USD ($)
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative effect adjustment on retained earnings	$ 56.1
Recognize of unamortized tax expense previously deferred	40.1
Deferred tax assets previously unrecognized	$ 96.2

Business Acquisitions and Div49

Business Acquisitions and Divestitures - Additional Information (Details)	Mar. 01, 2017USD ($)	Jan. 26, 2017USD ($)$ / sharesshares	Jan. 22, 2017aMMcfbbl	Mar. 31, 2017USD ($)	Mar. 31, 2017USD ($)
Business Acquisition [Line Items]
Public offering of common shares (including underwriters' overallotment option) | shares		9,200,000
Shares issued price | $ / shares		$ 57.65
Proceeds from issuance of common stock		$ 524,200,000			$ 664,800,000
Maximum [Member]
Business Acquisition [Line Items]
Estimated useful lives of fair value					20 years
Minimum [Member]
Business Acquisition [Line Items]
Estimated useful lives of fair value					15 years
Permian Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Cash payments related to acquisition	$ 484,100,000
Acquired debt and all other assumed liabilities included in purchase consideration	90,000,000
Revenues from acquired businesses				$ 8,100,000
Net loss from acquired business				(1,600,000)
Acquisition-related expenses					$ 5,100,000
Estimated useful lives of fair value					15 years
Permian Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment	$ 935,000,000			$ 935,000,000	$ 935,000,000
New Delaware [Member]
Business Acquisition [Line Items]
Oil and gas contracts average weighted contract life			14 years
Gas processing capacity | MMcf			70
Crude gathering capacity | bbl			40,000
New Delaware [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering systems | a			145,000
New Midland [Member]
Business Acquisition [Line Items]
Oil and gas contracts average weighted contract life			13 years
Gas processing capacity | MMcf			10
Crude gathering capacity | bbl			40,000
New Midland [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering systems | a			105,000

Business Acquisitions and Div50

Business Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pro forma consolidated results of operations [Abstract]
Revenues	$ 2,126.7	$ 1,445
Net income (loss)	$ (111.4)	$ (12.5)

Business Acquisitions and Div51

Business Acquisitions and Divestitures - Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions		Mar. 01, 2017		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Fair Value of Consideration Transferred [Abstract]
Cash paid, net of cash acquired				$ 480.8
Purchase consideration payable				90	$ 0
Permian Acquisition [Member]
Fair Value of Consideration Transferred [Abstract]
Cash paid, net of cash acquired	[1]	$ 480.8
Purchase consideration payable		90	[2]	$ 90		$ 0
Contingent consideration		461.6
Total fair value of consideration transferred		$ 1,032.4
[1]	Net of cash acquired of $3.3 million.
[2]	The payable will be settled in cash within 90 days from March 1, 2017.

Business Acquisitions and Div52

Business Acquisitions and Divestitures - Fair Value of Consideration Transferred (Parenthetical) (Details) - Permian Acquisition [Member] - USD ($) $ in Millions	Mar. 01, 2017	Mar. 31, 2017
Fair Value of Consideration Transferred [Abstract]
Cash acquired from acquisition	$ 3.3
Business combination purchase consideration cash payment period		90 days
Business combination purchase consideration cash payment effective date		Mar. 1, 2017

Business Acquisitions and Div53

Business Acquisitions and Divestitures - Fair Value of the Assets and Liabilities Assumed at Acquisition Date (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 01, 2017	Dec. 31, 2016	Mar. 31, 2016
Fair value determination [Abstract]
Goodwill	$ 369		$ 210	$ 393
Permian Acquisition [Member]
Fair value determination [Abstract]
Trade and other current receivables, net		$ 6.5
Other current assets		0.6
Property, plant and equipment		255.4
Intangible assets		625.6
Current liabilities		(14.3)
Other long-term liabilities		(0.4)
Total identifiable net assets		873.4
Goodwill	$ 159	159
Total fair value of consideration transferred		$ 1,032.4

Business Acquisitions and Div54

Business Acquisitions and Divestitures - Additional Information Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 01, 2017	Dec. 31, 2016	Mar. 31, 2016
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Goodwill	$ 369		$ 210	$ 393
Trade receivables, preliminary fair value		$ 6.5
Permian Acquisition [Member]
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Goodwill	$ 159	$ 159

Business Acquisitions and Div55

Business Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - USD ($)	1 Months Ended	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Mar. 01, 2017	Mar. 31, 2016
Business Acquisition [Line Items]
Change in fair value of contingent liability		$ 3,300,000
Permian Acquisition [Member]
Business Acquisition [Line Items]
Potential earn-out payments of preliminary acquisition date fair value	$ 461,600,000	461,600,000	$ 461,600,000	$ 0
Change in fair value of contingent liability	3,200,000	3,200,000
Permian Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Additional cash paid in potential earn-out payment	$ 935,000,000	$ 935,000,000	$ 935,000,000

Business Acquisitions and Div56

Business Acquisitions and Divestitures - Additional Information 2017 Divestiture (Details) - USD ($) $ in Millions		Apr. 04, 2017	Mar. 31, 2017	Mar. 31, 2016
Business Divestitures [Line Items]
Loss from sale of VGS	[1]		$ (16.1)	$ (0.9)
Venice Gathering System, L.L.C. [Member] | Not Qualify as Discontinued Operations [Member]
Business Divestitures [Line Items]
Loss from sale of VGS			$ (16.1)
Subsequent Event [Member]
Business Divestitures [Line Items]
Loss from sale of VGS		$ (16.1)
Subsequent Event [Member] | Venice Gathering System, L.L.C. [Member] | Not Qualify as Discontinued Operations [Member]
Business Divestitures [Line Items]
Subsidiary ownership interest sale percentage		100.00%
Proceeds from divestiture of businesses		$ 0.4
Venice Energy Services Company, L.L.C. [Member]
Business Divestitures [Line Items]
Ownership interest			76.80%
[1]	Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Commodities	$ 65.1	$ 126.9
Materials and supplies	10.4	10.8
Inventories, net	$ 75.5	$ 137.7

Property, Plant and Equipment58

Property, Plant and Equipment and Intangible Assets - Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 12,957	$ 12,518.7
Accumulated depreciation	(2,993.6)	(2,827.7)
Property, plant and equipment, net	9,963.4	9,691
Intangible assets	2,662.2	2,036.6
Accumulated amortization	(423.4)	(382.6)
Intangible assets, net	$ 2,238.8	1,654
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	15 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 6,777.7	6,626.8
Gathering Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Gathering Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 3,506.9	3,390.2
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,231.7	1,205
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	$ 427.9	451.4
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	$ 280.6	274.2
Other Property, Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Other Property, Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 121.6	121.3
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 610.6	$ 449.8

Property, Plant and Equipment59

Property, Plant and Equipment and Intangible Assets - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Additions from acquisition	$ 625.6
Estimated amortization expense for intangible assets [Abstract]
2,017	184.2
2,018	177.4
2,019	166.4
2,020	154.2
2,021	144.3
Permian Acquisitions [Member]
Property, Plant and Equipment [Line Items]
Additions from acquisition	$ 625.6
Estimated useful lives	15 years
Atlas Energy [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives		20 years
Badlands [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives		20 years

Property, Plant and Equipment60

Property, Plant and Equipment and Intangible Assets - Schedule of Changes in Intangible Assets (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Finite Lived Intangible Assets Roll Forward
Balance at December 31, 2016	$ 1,654
Additions from Permian Acquisition	625.6
Amortization	(40.8)
Balance at March 31, 2017	$ 2,238.8

Goodwill - Additional Informati

Goodwill - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill impairment	$ 0	$ 24

Goodwill - Changes in Net Book

Goodwill - Changes in Net Book Value of Goodwill (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Goodwill [Roll Forward]
Beginning balance	$ 210
Permian Acquisition, March 1, 2017 (preliminary valuation)	159
Ending balance	369
WestTX [Member]
Goodwill [Roll Forward]
Beginning balance	174.7
Permian Acquisition, March 1, 2017 (preliminary valuation)	0
Ending balance	174.7
SouthTX [Member]
Goodwill [Roll Forward]
Beginning balance	35.3
Permian Acquisition, March 1, 2017 (preliminary valuation)	0
Ending balance	35.3
Permian [Member]
Goodwill [Roll Forward]
Beginning balance	0
Permian Acquisition, March 1, 2017 (preliminary valuation)	159
Ending balance	$ 159

Investments in Unconsolidated63

Investments in Unconsolidated Affiliates - Additional Information (Details) - Targa Resources Partners LP [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)JointVenture
Gulf Coast Fractionators LP [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	38.80%
T2 Joint Ventures [Member]
Schedule of Equity Method Investments [Line Items]
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture	3
Unamortized excess fair value over Joint Ventures	$ 30.1
Preliminary estimated useful lives of the underlying assets	20 years
T2 LaSalle [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	75.00%
T2 Eagle Ford [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50.00%
T2 EF Cogen [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50.00%
Equity (earnings) loss of unconsolidated affiliates	$ 12

Investments in Unconsolidated64

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Schedule of Equity Method Investments [Line Items]
Beginning of period		$ 240.8
Equity earnings (loss)		(12.6)	$ (4.8)
Cash distributions	[1]	(2.7)
Contributions for expansion projects	[2]	1.5
End of period		227
Targa Resources Partners LP [Member] | Gulf Coast Fractionators LP [Member]
Schedule of Equity Method Investments [Line Items]
Beginning of period		46.1
Equity earnings (loss)		3.7
Cash distributions	[1]	(2.7)
End of period		47.1
Targa Resources Partners LP [Member] | T2 LaSalle [Member]
Schedule of Equity Method Investments [Line Items]
Beginning of period		58.6
Equity earnings (loss)		(1.1)
Contributions for expansion projects	[2]	0.3
End of period		57.8
Targa Resources Partners LP [Member] | T2 Eagle Ford [Member]
Schedule of Equity Method Investments [Line Items]
Beginning of period		118.6
Equity earnings (loss)		(2.7)
Contributions for expansion projects	[2]	1.1
End of period		117
Targa Resources Partners LP [Member] | T2 EF Cogen [Member]
Schedule of Equity Method Investments [Line Items]
Beginning of period		17.5
Equity earnings (loss)		(12.5)
Contributions for expansion projects	[2]	0.1
End of period		$ 5.1
[1]	During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.
[2]	Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

Investments in Unconsolidated65

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Schedule of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate		$ 3,400,000
Contributions of property, plant and equipment	$ 1,000,000	$ 0
T2 Eagle Ford [Member]
Schedule of Equity Method Investments [Line Items]
Contributions of property, plant and equipment	1,000,000
Targa Resources Partners LP [Member]
Schedule of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate	$ 0

Accounts Payable and Accrued 66

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$ 512.1	$ 574.4
Other goods and services	122.2	117
Purchase consideration payable	90	0
Interest	52.7	52.3
Compensation and benefits	20.2	37.2
Income and other taxes	22.6	24.2
Preferred Series A dividends payable	22.9	22.9
Other	24.5	15.5
Accounts payable and accrued liabilities	$ 867.2	$ 843.5

Accounts Payable and Accrued 67

Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Outstanding checks	$ 27.4	$ 30.5

Debt Obligations - Summary Of D

Debt Obligations - Summary Of Debt Obligations (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Current Obligations of the Partnership [Abstract]
Current debt	[1]	$ 285	$ 275
Senior unsecured notes, 5% fixed rate, due January 2018		250.5	0
Total current debt		535.5	275
Debt issuance costs, net of amortization		(0.6)	0
Current maturities of debt		534.9	275
Long-term [Abstract]
Long-term debt		4,213.3	4,606
Long-term debt including Unamortized premium(discount) and Debt issuance costs		4,241.8	4,640.1
Debt issuance costs, net of amortization		(28.5)	(34.1)
Total debt obligations		4,748.2	4,881
Letters of credit outstanding		15.8	13.2
Secured Debt [Member] | TRC Senior Secured Term Loan due February 2022 [Member]
Long-term [Abstract]
Long-term debt		0	160
Unamortized discount		0	(2.2)
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Long-term [Abstract]
Long-term debt	[2]	6.5	6.5
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Long-term [Abstract]
Long-term debt	[2]	48.1	48.1
Unamortized premium	[2]	0.5	0.5
Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility due February 2020 [Member]
Long-term [Abstract]
Long-term debt	[3]	435	275
Targa Resources Partners LP [Member] | TRP Senior Secured Revolving Credit Facility due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[1],[4]	0	150
Targa Resources Partners LP [Member] | Secured Debt [Member] | TRC Senior Secured Revolving Credit Facility [Member]
Long-term [Abstract]
Letters of credit outstanding	[3]	0	0
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Long-term [Abstract]
Long-term debt	[1]	0	250.5
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	[1]	749.4	749.4
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	[1]	278.7	278.7
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	[1]	559.6	559.6
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	[1]	583.9	583.9
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Long-term [Abstract]
Long-term debt	[1]	580.1	580.1
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member]
Long-term [Abstract]
Long-term debt	[1]	500	500
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member]
Long-term [Abstract]
Long-term debt	[1]	500	500
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due October 2020 [Member]
Long-term [Abstract]
Letters of credit outstanding	[4]	$ 15.8	$ 13.2
[1]	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership or Targa Pipeline Partners, L.P. (“TPL”).
[2]	TPL notes are not guaranteed by us or the Partnership.
[3]	As of March 31, 2017, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million.
[4]	As of March 31, 2017, availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

Debt Obligations - Summary Of69

Debt Obligations - Summary Of Debt Obligations (Parenthetical) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Feb. 23, 2017	Dec. 31, 2016
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 350,000,000	$ 275,000,000
Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility due February 2020 [Member]
Debt Instrument [Line Items]
Maturity date	Feb. 29, 2020
Maximum borrowing capacity	$ 670,000,000
Remaining borrowing capacity	$ 235,000,000
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Debt Instrument [Line Items]
Maturity date	Nov. 15, 2021
Interest rate on fixed rate debt	4.75%
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2023
Interest rate on fixed rate debt	5.875%
Secured Debt [Member] | TRC Senior Secured Term Loan due February 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Feb. 28, 2022
Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2017 [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 31, 2017
Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due October 2020 [Member]
Debt Instrument [Line Items]
Maturity date	Oct. 31, 2020
Maximum borrowing capacity	$ 1,600,000,000
Remaining borrowing capacity	$ 1,584,200,000
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 15, 2018
Interest rate on fixed rate debt	5.00%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% notes due November 2019 [Member]
Debt Instrument [Line Items]
Maturity date	Nov. 15, 2019
Interest rate on fixed rate debt	4.125%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022
Interest rate on fixed rate debt	6.375%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]
Debt Instrument [Line Items]
Maturity date	May 1, 2023
Interest rate on fixed rate debt	5.25%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]
Debt Instrument [Line Items]
Maturity date	Nov. 15, 2023
Interest rate on fixed rate debt	4.25%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Debt Instrument [Line Items]
Maturity date	Mar. 15, 2024
Interest rate on fixed rate debt	6.75%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member]
Debt Instrument [Line Items]
Maturity date	Feb. 28, 2025
Interest rate on fixed rate debt	5.125%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member]
Debt Instrument [Line Items]
Maturity date	Feb. 28, 2027
Interest rate on fixed rate debt	5.375%

Debt Obligations - Range of Int

Debt Obligations - Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations (Details)	Mar. 31, 2017
TRC Revolver [Member]
Debt Instrument [Line Items]
Weighted average interest rate incurred	2.60%
TRP Revolver [Member]
Debt Instrument [Line Items]
Weighted average interest rate incurred	3.20%
Secured Debt [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	5.75%	[1]
Weighted average interest rate incurred	5.75%	[1]
Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	1.80%
Weighted average interest rate incurred	1.80%
Minimum [Member] | TRC Revolver [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	2.50%
Minimum [Member] | TRP Revolver [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	3.00%
Maximum [Member] | TRC Revolver [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	4.50%
Maximum [Member] | TRP Revolver [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	5.30%
[1]	The TRC Senior secured term loan is a Eurodollar rate loan with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of 4.75%.

Debt Obligations - Range of I71

Debt Obligations - Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations (Parenthetical) (Details) - Secured Debt [Member]	3 Months Ended
	Mar. 31, 2017
LIBOR [Member]
Debt Instrument [Line Items]
Senior secured loan variable rate	1.00%
Eurodollar Rate [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt	4.75%

Debt Obligations - Additional I

Debt Obligations - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 14, 2017	Feb. 23, 2017	Dec. 31, 2016
Senior secured term loan [Member]
Debt Instrument [Line Items]
Outstanding senior secured term loan		$ 160
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 350	$ 275
Outstanding securitization facility	$ 285

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Other Liabilities Noncurrent [Line Items]
Asset retirement obligations	$ 68	$ 64.6
Mandatorily redeemable preferred interests	71.9	68.5
Deferred revenue	69	69.8
Other liabilities	15.2	12.2
Total long-term liabilities	688.9	$ 215.1
Permian Acquisition [Member]
Other Liabilities Noncurrent [Line Items]
Permian Acquisition contingent consideration	$ 464.8

Other Long-term Liabilities - C

Other Long-term Liabilities - Changes in Aggregate ARO (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Changes in aggregate asset retirement obligations [Roll Forward]
Beginning balance		$ 64.6
Additions	[1]	0.4
Change in cash flow estimate		1.7	$ (9.1)
Accretion expense		1.3	$ 1.2
Ending balance		$ 68
[1]	Amount reflects AROs assumed from the Permian Acquisition

Other Long-term Liabilities, Ma

Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)JointVenture	Mar. 31, 2016USD ($)
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2016	$ 68.5
Change in estimated redemption value included in interest expense	2.5	$ (18.5)
Balance at March 31, 2017	71.9
Mandatorily Redeemable Noncontrolling Interests [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2016	68.5
Income attributable to mandatorily redeemable preferred interests	0.9
Change in estimated redemption value included in interest expense	2.5
Balance at March 31, 2017	$ 71.9
Mandatorily Redeemable Noncontrolling Interests [Member] | West OK [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Ownership interest	100.00%
Mandatorily Redeemable Noncontrolling Interests [Member] | West TX [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Ownership interest	72.80%
Mandatorily Redeemable Noncontrolling Interests [Member] | Joint Ventures [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Number of joint ventures | JointVenture	2

Other Long-term Liabilities, De

Other Long-term Liabilities, Deferred Revenue (Details) - Channelview Splitter [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)	Dec. 27, 2015USD ($)bbl
Deferred Revenue and Other [Abstract]
Crude and condensate splitter, barrel per day | bbl		35,000
Storage capacity of Channelview Terminal | bbl		730,000
Splitter estimated cost | $		$ 140
Annual deferred revenue payments receivable through 2022 | $	$ 43

Other Long-term Liabilities, Co

Other Long-term Liabilities, Components of Deferred Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Component Of Deferred Revenue [Line Items]
Total deferred revenue	$ 69	$ 69.8
Splitter Agreement [Member]
Component Of Deferred Revenue [Line Items]
Total deferred revenue	43	43
Gas Contract Amendment [Member]
Component Of Deferred Revenue [Line Items]
Total deferred revenue	19.3	19.7
Other Deferred Revenue [Member]
Component Of Deferred Revenue [Line Items]
Total deferred revenue	$ 6.7	$ 7.1

Other Long-term Liabilities -78

Other Long-term Liabilities - Changes in Deferred Revenue (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Changes in deferred revenue [Roll Forward]
Balance at December 31, 2016	$ 69.8
Revenue recognized	(0.8)
Balance at March 31, 2017	$ 69

Other Long-term Liabilities, 79

Other Long-term Liabilities, Contingent Consideration (Details) - USD ($)	1 Months Ended	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Mar. 01, 2017
Other Liabilities Noncurrent [Line Items]
Increase in fair value of contingent liability		$ 3,300,000
Permian Acquisition [Member]
Other Liabilities Noncurrent [Line Items]
Contingent consideration			$ 461,600,000
Increase in fair value of contingent liability	$ 3,200,000	3,200,000
Permian Acquisition contingent consideration	464,800,000	464,800,000
Permian Acquisition [Member] | Maximum [Member]
Other Liabilities Noncurrent [Line Items]
Additional cash paid in potential earn-out payment	$ 935,000,000	$ 935,000,000	$ 935,000,000

Preferred Stock - Additional In

Preferred Stock - Additional Information (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)$ / sharesshares	Mar. 31, 2016USD ($)Trancheshares	Dec. 31, 2016USD ($)$ / sharesshares
Class Of Stock [Line Items]
Number of tranches sold to investors | Tranche		2
Gross proceeds		$ 994.1
Term of preferred stock warrants	7 years
Net Proceeds- Initial Relative Fair Value Allocation	$ 969.3
Allocation to BCF	$ (614.4)
Accounting Conversion Price Of Convertible Preferred Stock | $ / shares	$ 17.02
Conversion price of preferred stock into common stock | $ / shares	$ 20.77
Preferred Series A dividends payable	$ 22.9		$ 22.9
Preferred stock dividend paid	$ 22.9
Accrued preferred dividends payable date	May 15, 2017
Deemed dividends on Series A preferred stock	$ 6.1	$ 0
Series A Warrants [Member]
Class Of Stock [Line Items]
Preferred stock, shares issued to investors | shares	13,550,004
Exercise price of warrants | $ / shares	$ 18.88
Net Proceeds- Initial Relative Fair Value Allocation	$ 135.7
Series B Warrants [Member]
Class Of Stock [Line Items]
Preferred stock, shares issued to investors | shares	6,533,727
Exercise price of warrants | $ / shares	$ 25.11
Net Proceeds- Initial Relative Fair Value Allocation	$ 46.5
Series A Preferred Stock [Member]
Class Of Stock [Line Items]
Preferred stock, shares issued to investors | shares	965,100		965,100
Preferred stock, liquidation per share | $ / shares	$ 1,000		$ 1,000
Preferred stock, percentage of dividend	9.50%
Preferred stock dividend payment terms	fixed dividend payable quarterly 45 days after the end of each fiscal quarter
Preferred stock redemption premium percentage in sixth year	10.00%
Preferred stock redemption premium percentage in sixth year and thereafter	5.00%
Preferred stock redemption premium percentage in twelfth year	10.00%
Volume Weighted Average Share Price | $ / shares	$ 18.88
Stock conversion, description	If the investors do not elect to convert their Series A Preferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if the VWAP for the ten preceding trading days is greater than 120% of the conversion price
Preferred stock conversion price threshold percentage	120.00%
Maximum number of common share would be issued upon conversion of preferred share | shares	46,466,057
Net Proceeds- Initial Relative Fair Value Allocation	$ 787.1
Preferred stock, discount on shares	178.1
Allocation to BCF	$ 614.4
Series A Preferred Stock [Member] | 10% Redemption Premium
Class Of Stock [Line Items]
Preferred stock conversion redemption premium percentage in sixth year	10.00%
Benefit from conversion right by redemption premium	$ 96.5
Series A Preferred Stock [Member] | 5% Redemption Premium
Class Of Stock [Line Items]
Benefit from conversion right by redemption premium	$ 48.3
Preferred stock conversion redemption premium percentage in year seven through twelve year	5.00%
Private Placement [Member] | Series A Warrants [Member]
Class Of Stock [Line Items]
Conversion of warrant into preferred stock | shares		13,550,004
Private Placement [Member] | Series B Warrants [Member]
Class Of Stock [Line Items]
Conversion of warrant into preferred stock | shares		6,533,727
Private Placement [Member] | Series A Preferred Stock [Member]
Class Of Stock [Line Items]
Preferred stock, shares issued to investors | shares		965,100

Accounting for Series A Preferr

Accounting for Series A Preferred Stock (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Class Of Stock [Line Items]
Proceeds from issuance of preferred stock and warrants		$ 994.1
Transaction fees	$ (24.8)
Net Proceeds- Initial Relative Fair Value Allocation	969.3
Allocation to BCF	614.4
Per balance sheet upon issuance	614.4
Series A Warrants [Member]
Class Of Stock [Line Items]
Net Proceeds- Initial Relative Fair Value Allocation	135.7
Per balance sheet upon issuance	135.7
Series B Warrants [Member]
Class Of Stock [Line Items]
Net Proceeds- Initial Relative Fair Value Allocation	46.5
Per balance sheet upon issuance	46.5
Series A Preferred Stock [Member]
Class Of Stock [Line Items]
Net Proceeds- Initial Relative Fair Value Allocation	787.1
Allocation to BCF	(614.4)
Per balance sheet upon issuance	$ 172.7

Common Stock and Related Matt82

Common Stock and Related Matters - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 26, 2017	Apr. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Securities Financing Transaction [Line Items]
Issuance of common stock (in shares)	9,200,000
Shares issued price	$ 57.65
Proceeds from issuance of common stock	$ 524.2		$ 664.8
Receivables from common stock offerings			$ 19.6
Warrants exercised (in shares)			0	19,983,843
Shares of Common Stock [Member]
Securities Financing Transaction [Line Items]
Issuance of common stock (in shares)			11,886,000
Exercise of warrants - share settled (in shares)				11,336,856
Series A Warrants [Member]
Securities Financing Transaction [Line Items]
Exercisable warrants outstanding			67,392
Series B Warrants [Member]
Securities Financing Transaction [Line Items]
Exercisable warrants outstanding			32,496
Equity Distribution Agreement December 2016 [Member]
Securities Financing Transaction [Line Items]
Issuance of common stock (in shares)			2,686,460
Proceeds from issuance of common stock			$ 152.8
Remaining amount of common stock available under equity distribution agreement			$ 516.5
Equity Distribution Agreement December 2016 [Member] | Subsequent Event [Member]
Securities Financing Transaction [Line Items]
Issuance of common stock (in shares)		1,464,408
Proceeds from issuance of common stock		$ 85.8
Remaining amount of common stock available under equity distribution agreement		430
Receivables from common stock offerings		$ 19.6

Common Stock and Related Matt83

Common Stock and Related Matters - Dividends Declared And Or Paid (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Dividends Payable [Line Items]
Accrued preferred dividends payable date		May 15, 2017
Dividend Declared per Share of Common Stock		$ 0.91	$ 0.91
Dividend Declared Q1 2017 [Member]
Dividends Payable [Line Items]
Accrued preferred dividends payable date		May 16, 2017
Total Common Dividends Declared		$ 182.8
Amount of Common Dividends Paid		180.3
Accrued Dividends	[1]	$ 2.5
Dividend Declared per Share of Common Stock		$ 0.91000
Dividend Declared, Q4 2016 [Member]
Dividends Payable [Line Items]
Accrued preferred dividends payable date		Feb. 15, 2017
Total Common Dividends Declared		$ 178.3
Amount of Common Dividends Paid		176.5
Accrued Dividends	[1]	$ 1.8
Dividend Declared per Share of Common Stock		$ 0.91000
[1]	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Partnership Units and Related84

Partnership Units and Related Matters - Summary of Distributions Declared or Paid by the Partnership (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Distributions Declared [Member]
Distributions declared or paid by the Partnership [Abstract]
Distributions payable date	May 11, 2017
Total Distributions	$ 209.6
Distributions to Targa Resources Corp.	$ 206.8
Distributions Paid [Member]
Distributions declared or paid by the Partnership [Abstract]
Distributions payable date		Feb. 10, 2017
Total Distributions		$ 198.1
Distributions to Targa Resources Corp.		$ 195.3

Partnership Units and Related85

Partnership Units and Related Matters - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended		4 Months Ended
	Apr. 30, 2017	Oct. 31, 2015	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2017
Limited Partners Capital Account [Line Items]
Total capital contributions to partnership			$ 655
Percentage of capital contribution towards partner's interest maintained			8.80%
Percentage of general partner's interest maintained			2.00%
Distributions from partnership			$ 2.8	$ 141.7
Subsequent Event [Member]
Limited Partners Capital Account [Line Items]
Distributions declaration month	2017-04
Distribution declared	$ 0.1875
Distributions from partnership	$ 0.9
Distributions payable date	May 15, 2017
Series A Preferred Units due November 1, 2020 [Member] | LIBOR [Member]
Limited Partners Capital Account [Line Items]
Percentage of variable interest rate for distribution on preferred units upon maturity		7.71%
Series A Preferred Units [Member]
Limited Partners Capital Account [Line Items]
Preferred unit, issued		5,000,000
Preferred unit, par value (in dollar per unit)		$ 25
Preferred unit, distribution interest rate		9.00%
Series A Cumulative Redeemable Perpetual Preferred Units [Member]
Limited Partners Capital Account [Line Items]
Distribution to preferred unitholders			$ 2.8
TRC/TRP Merger
Limited Partners Capital Account [Line Items]
Percentage of capital contribution towards partner's interest maintained					98.00%
Percentage of general partner's interest maintained					2.00%

Earnings per Common Share (Deta

Earnings per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income	$ (110.5)	$ (0.7)
Net income (loss) attributable to noncontrolling interests	8.8	2
Less: Dividends on preferred stock	29	3.8
Net income (loss) attributable to common shareholders	$ (148.3)	$ (6.5)
Weighted average shares outstanding - basic (in shares)	191.8	106.6
Net income available per common share - basic (in dollars per share)	$ (0.77)	$ (0.06)
Weighted average shares outstanding - basic (in shares)	191.8	106.6
Weighted average shares outstanding - diluted (in shares)	191.8	106.6
Net income available per common share - diluted (in dollars per share)	$ (0.77)	$ (0.06)

Earnings per Common Share - Sum

Earnings per Common Share - Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share (Details) - shares shares in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Unvested Restricted Stock Awards [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive shares excluded from the determination of diluted earnings per share (in shares)		1.3	0.1
Warrants to Purchase Common Stock [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive shares excluded from the determination of diluted earnings per share (in shares)		0.1	2
Series A Preferred Stock [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive shares excluded from the determination of diluted earnings per share (in shares)	[1]	46.5	13.8
[1]	The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock. See Note 12 – Preferred Stock

Earnings per Common Share - S88

Earnings per Common Share - Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share (Parenthetical) (Details) - Series A Preferred Stock [Member]	3 Months Ended
	Mar. 31, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Preferred stock redemption premium percentage in sixth year	10.00%
Preferred stock redemption premium percentage after sixth year	5.00%

Derivative Instruments and He89

Derivative Instruments and Hedging Activities - Additional Information (Details) - USD ($)	3 Months Ended		25 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2017	Feb. 27, 2015
Derivative Line [Items]
Pro forma net presentation, asset	$ 15,400,000		$ 15,400,000
Amount expected to reclassify commodity hedge related deferred losses to earnings before income taxes	10,800,000		10,800,000
Amount of deferred losses to be reclassified into earnings before income taxes over next twelve months	$ (2,600,000)		(2,600,000)
Targa Resources Partners LP [Member] | Targa Pipeline Partners LP [Member]
Derivative Line [Items]
Fair value of derivative assets				$ 102,100,000
Acquisition date	Feb. 27, 2015
Fair value of derivative contracts received as component of derivative contract settlement	$ 3,000,000	$ 8,700,000	$ 97,600,000
Ineffectiveness losses	$ 0
Targa Resources Partners LP [Member] | Targa Pipeline Partners LP [Member] | Maximum [Member]
Derivative Line [Items]
Ineffectiveness losses		$ 100,000

Derivative Instruments and He90

Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details) - Targa Resources Partners LP [Member]	3 Months Ended
	Mar. 31, 2017MMBTUbbl
Year 2017 [Member] | Swaps [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	2,690
Year 2017 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	141,960
Year 2017 [Member] | Swaps [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	14,143
Year 2017 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	95,963
Year 2017 [Member] | Future [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2017 [Member] | Future [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	5,702
Year 2017 [Member] | Options [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	1,380
Year 2017 [Member] | Options [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	22,900
Year 2017 [Member] | Options [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	1,647
Year 2018 [Member] | Swaps [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	2,190
Year 2018 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	100,500
Year 2018 [Member] | Swaps [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	6,658
Year 2018 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	1,103
Year 2018 [Member] | Future [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	1,103
Year 2018 [Member] | Future [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	1,288
Year 2018 [Member] | Options [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	691
Year 2018 [Member] | Options [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	9,486
Year 2018 [Member] | Options [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	1,676
Year 2019 [Member] | Swaps [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	1,063
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	61,383
Year 2019 [Member] | Swaps [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	5,339
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2019 [Member] | Future [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2019 [Member] | Future [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Year 2019 [Member] | Options [Member] | Condensate [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	590
Year 2019 [Member] | Options [Member] | Natural Gas [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2019 [Member] | Options [Member] | NGL [Member]
Derivative Line [Items]
Notional volumes of commodity hedges (in Bbl per day)	0

Derivative Instruments and He91

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets, Current	$ 23.9	$ 16.8
Derivative assets, Long-term	21.6	5.1
Derivative assets	45.5	21.9
Derivative liabilities	30.1	75.2
Derivative liabilities, Current	22.2	49.1
Derivative liabilities, Long-term	7.9	26.1
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	45.2	21.8
Derivative liabilities	28.7	74.7
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	20.8	48.6
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-Term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	7.9	26.1
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	23.6	16.7
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-Term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	21.6	5.1
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1.4	0.5
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1.4	0.5
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0.3	0.1
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-Term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	$ 0.3	$ 0.1

Derivative Instruments and He92

Derivative Instruments and Hedging Activities - Pro Forma Impact Of Offsetting Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross asset	$ 45.5	$ 21.9
Gross liability	(30.1)	(75.2)
Derivative assets	45.5	21.9
Pro forma net presentation, asset, total	27.9	5.7
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	45.1	21.9
Gross liability	(27.4)	(64.8)
Pro forma net presentation, asset	27.5	5.7
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.4
Pro forma net presentation, asset, total	0.4
Current Assets from Risk Management Activities [Member]
Derivative Asset [Abstract]
Gross asset	23.9	16.8
Pro forma net presentation, asset, current	10.9	5.7
Current Assets from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	23.8	16.8
Pro forma net presentation, asset	10.8	5.7
Current Assets from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.1
Pro forma net presentation, asset, current	0.1
Long-Term Assets from Risk Management Activities [Member]
Derivative Asset [Abstract]
Gross asset	21.6	5.1
Pro forma net presentation, asset, noncurrent	17
Long-Term Assets from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	21.3	$ 5.1
Pro forma net presentation, asset	16.7
Long-Term Assets from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.3
Pro forma net presentation, asset, noncurrent	$ 0.3

Derivative Instruments and He93

Derivative Instruments and Hedging Activities - Pro Forma Impact Of Offsetting Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Liability [Abstract]
Gross liability	$ (30.1)	$ (75.2)
Pro forma net presentation, liability, total	(12.4)	(52)
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(27.4)	(64.8)
Pro forma net presentation, liability, total	(9.7)	(41.6)
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(2.7)	(10.4)
Pro forma net presentation, liability, total	(2.7)	(10.4)
Current Liabilities from Risk Management Activities [Member]
Derivative Liability [Abstract]
Gross liability	(22.2)	(49.1)
Pro forma net presentation, liability, current	(9.1)	(31)
Current Liabilities from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(20.8)	(46.1)
Pro forma net presentation, liability, current	(7.7)	(28)
Current Liabilities from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(1.4)	(3)
Pro forma net presentation, liability, current	(1.4)	(3)
Long-Term Liabilities from Risk Management Activities [Member]
Derivative Liability [Abstract]
Gross liability	(7.9)	(26.1)
Pro forma net presentation, liability, noncurrent	(3.3)	(21)
Long-Term Liabilities from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(6.6)	(18.7)
Pro forma net presentation, liability, noncurrent	(2)	(13.6)
Long-Term Liabilities from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(1.3)	(7.4)
Pro forma net presentation, liability, noncurrent	$ (1.3)	$ (7.4)

Derivative Instruments and He94

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross collateral	$ 0.1	$ 7
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	0.1	7
Current Assets from Risk Management Activities [Member]
Derivative Asset [Abstract]
Gross collateral	0.1	7
Current Assets from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	$ 0.1	$ 7

Derivative Instruments and He95

Derivative Instruments and Hedging Activities - Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	$ (6.1)	$ 24.2
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives	(0.8)	1.8
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	$ 66.2	$ 6.7

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)Swap
Fair Value Disclosures [Abstract]
Derivative financial instruments, fair value, net	$ 15.4
Derivative fair value of net liability if commodity price increases by 10 percent	47.5
Derivative fair value of net asset if commodity price decreases by 10 percent	$ 79
Number of natural gas basis swaps categorized as Level 3 | Swap	17

Fair Value Measurements - Break

Fair Value Measurements - Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts		$ 27.9	$ 5.7
Liabilities from commodity derivative contracts		12.4	52
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	37.7	21
Liabilities from commodity derivative contracts	[1]	22.1	74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		80	73.5
Carrying Value [Member] | TRC Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		435	275
Carrying Value [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	157.8
Carrying Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	150
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		285	275
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,057.3	4,057.3
Carrying Value [Member] | Permian Acquisitions [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[2]	464.8
Carrying Value [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[3]	2.7	2.6
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	37.7	21
Liabilities from commodity derivative contracts	[1]	22.1	74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		80	73.5
Fair Value [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	0	0
Liabilities from commodity derivative contracts	[1]	0	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0	0
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	35.7	19.6
Liabilities from commodity derivative contracts	[1]	20.8	69.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0	0
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	2	1.4
Liabilities from commodity derivative contracts	[1]	1.3	4.9
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		0	0
Fair Value [Member] | TRC Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		435	275
Fair Value [Member] | TRC Revolver [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | TRC Revolver [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		435	275
Fair Value [Member] | TRC Revolver [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Senior Secured Term Loan [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	158.4
Fair Value [Member] | Senior Secured Term Loan [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Senior Secured Term Loan [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	158.4
Fair Value [Member] | Senior Secured Term Loan [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	150
Fair Value [Member] | TRP Revolver [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | TRP Revolver [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	150
Fair Value [Member] | TRP Revolver [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
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		285	275
Fair Value [Member] | Partnership's Accounts Receivable Securitization Facility [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Partnership's Accounts Receivable Securitization Facility [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		285	275
Fair Value [Member] | Partnership's Accounts Receivable Securitization Facility [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,169.1	4,101.6
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,169.1	4,101.6
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		0	0
Fair Value [Member] | Permian Acquisitions [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[2]	464.8
Fair Value [Member] | Permian Acquisitions [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[2]	0
Fair Value [Member] | Permian Acquisitions [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[2]	0
Fair Value [Member] | Permian Acquisitions [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[2]	464.8
Fair Value [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[3]	2.7	2.6
Fair Value [Member] | Targa Pipeline Partners LP [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[3]	0	0
Fair Value [Member] | Targa Pipeline Partners LP [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[3]	0	0
Fair Value [Member] | Targa Pipeline Partners LP [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash paid in potential earn-out payment	[3]	$ 2.7	$ 2.6
[1]	The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 16 – 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]	We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures
[3]	We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value

Fair Value Measurements - Chang

Fair Value Measurements - Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period	$ (2.6)
New Level 3 derivative instruments	0
Transfers out of Level 3	0	[1]
Settlements included in Revenue	0
Unrealized gain/(loss) included in OCI	0
Balance, end of period	(467.5)
Targa Pipeline Partners LP [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(0.1)
Permian Acquisition [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(464.8)	[2]
Commodity Derivative Contracts Asset/(Liability) [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period	(3.6)
New Level 3 derivative instruments	(0.1)
Transfers out of Level 3	1.6	[1]
Settlements included in Revenue	0.2
Unrealized gain/(loss) included in OCI	2.6
Balance, end of period	0.7
Commodity Derivative Contracts Asset/(Liability) [Member] | Targa Pipeline Partners LP [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	0
Commodity Derivative Contracts Asset/(Liability) [Member] | Permian Acquisition [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	$ 0	[2]
[1]	Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.
[2]	Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

Contingencies - Additional Info

Contingencies - Additional Information (Details) - Environment Proceeding [Member] - USD ($)	Jan. 31, 2017	Mar. 31, 2017	Oct. 31, 2016
Versado Gas Processors L L C
Loss Contingencies [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			37.00%
Ownership interest in joint venture		63.00%
New Mexico Environment Department [Member]
Loss Contingencies [Line Items]
Litigation settlement amount	$ 29,223

Other Operating (Income) Exp100

Other Operating (Income) Expense (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Other Income And Expenses [Abstract]
(Gain) loss on sale or disposition of assets	[1]	$ 16.1	$ 0.9
Miscellaneous business tax		0.1	0.1
Total other operating (income) expense		$ 16.2	$ 1
[1]	Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Other Operating (Income) Exp101

Other Operating (Income) Expense (Parenthetical) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Other Operating Income Expense [Line Items]
Loss from sale of VGS	[1]	$ (16.1)	$ (0.9)
VGS [Member] | Not Qualify as Discontinued Operations [Member]
Other Operating Income Expense [Line Items]
Loss from sale of VGS		$ (16.1)
[1]	Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

Supplemental Cash Flow Infor102

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Mar. 01, 2017		Dec. 31, 2016
Cash:
Interest paid, net of capitalized interest	[1]	$ 56.1	$ 82.8
Income taxes paid, net of refunds		(0.2)	1
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment		8.3	16.9
Impact of capital expenditure accruals on property, plant and equipment		30	13.7
Transfers from materials and supplies inventory to property, plant and equipment		0.4	0.5
Contribution of property, plant and equipment to investment in unconsolidated affiliates.		1	0
Change in ARO liability and property, plant and equipment due to revised cash flow estimate		1.7	(9.1)
Non-cash financing activities:
Reduction of Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements		2.2	3.7
Accrued issue costs associated with Series A preferred stock		0	3.3
Receivables from equity offerings		19.6	0
Accrued deemed dividends of Series A Preferred Stock		6.1	0
Impact of accounting standard adoption recorded in retained earnings		56.1
Change in accrued dividends of Series A Preferred Stock		0	3.8
Non-cash balance sheet movements related to the Permian Acquisition:
Purchase consideration payable		90				$ 0
Non-cash balance sheet movements related to the TRC/TRP Merger:
Prepaid transaction costs reclassified in the additional paid-in capital		0	4.5
Issuance of common stock		0	0.1
Additional paid-in capital		0	3,115.5
Accumulated other comprehensive income		0	55.9
Noncontrolling interests		0	(4,119.9)
Deferred tax liability		0	948.4
Permian Acquisition [Member]
Non-cash balance sheet movements related to the Permian Acquisition:
Potential earn-out payments of preliminary acquisition date fair value		461.6	0	$ 461.6
Purchase consideration payable		$ 90	$ 0	$ 90	[2]
[1]	Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.
[2]	The payable will be settled in cash within 90 days from March 1, 2017.

Supplemental Cash Flow Infor103

Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Interest capitalized on major projects	$ 1.7	$ 4.8

Segment Information - Additiona

Segment Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2017Segment
Segment Reporting [Abstract]
Number of segments	2

Segment Information Revenues an

Segment Information Revenues and Operating Margin (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Sales of commodities	$ 1,858.1	$ 1,171
Fees from midstream services	254.5	271.4
Revenues	2,112.6	1,442.4
Operating margin	306.5	299.3
Gathering and Processing [Member]
Revenues
Revenues	999.8	640.8
Operating margin	177.4	115.6
Logistics and Marketing [Member]
Revenues
Revenues	1,911.1	1,240.9
Operating margin	130.1	157
Other Segment [Member]
Revenues
Revenues	(1)	26.8
Operating margin	(1)	26.8
Corporate and Eliminations [Member]
Revenues
Revenues	(797.3)	(466.1)
Operating margin		(0.1)
Operating Segments [Member]
Revenues
Sales of commodities	1,858.1	1,171
Fees from midstream services	254.5	271.4
Revenues	2,112.6	1,442.4
Operating Segments [Member] | Gathering and Processing [Member]
Revenues
Sales of commodities	166.7	110.3
Fees from midstream services	118.2	115.8
Revenues	284.9	226.1
Operating Segments [Member] | Logistics and Marketing [Member]
Revenues
Sales of commodities	1,692.4	1,033.9
Fees from midstream services	136.3	155.6
Revenues	1,828.7	1,189.5
Operating Segments [Member] | Other Segment [Member]
Revenues
Sales of commodities	(1)	26.8
Revenues	(1)	26.8
Intersegment Eliminations [Member] | Gathering and Processing [Member]
Revenues
Sales of commodities	713	412.6
Fees from midstream services	1.9	2.1
Revenues	714.9	414.7
Intersegment Eliminations [Member] | Logistics and Marketing [Member]
Revenues
Sales of commodities	75.4	47.3
Fees from midstream services	7	4.1
Revenues	82.4	51.4
Intersegment Eliminations [Member] | Corporate and Eliminations [Member]
Revenues
Sales of commodities	(788.4)	(459.9)
Fees from midstream services	(8.9)	(6.2)
Revenues	$ (797.3)	$ (466.1)

Segment Information, Other Fina

Segment Information, Other Financial Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017		Mar. 31, 2016		Dec. 31, 2016
Other financial information [Abstract]
Total assets		$ 13,653.8	[1]	$ 12,949.2	[1]	$ 12,871.2
Goodwill, net		369		393		$ 210
Capital expenditures		174.6		176.9
Operating Segments [Member] | Gathering and Processing [Member]
Other financial information [Abstract]
Total assets	[1]	10,780.4		10,219
Goodwill, net		369		393
Capital expenditures		139.2		103
Operating Segments [Member] | Logistics and Marketing [Member]
Other financial information [Abstract]
Total assets	[1]	2,687.2		2,501
Capital expenditures		34.6		73.1
Operating Segments [Member] | Other Segment [Member]
Other financial information [Abstract]
Total assets	[1]	44.9		105.7
Operating Segments [Member] | Corporate and Eliminations [Member]
Other financial information [Abstract]
Total assets	[1]	141.3		123.5
Capital expenditures		$ 0.8		$ 0.8
[1]	Corporate assets at the segment level primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

Segment Information - Summary o

Segment Information - Summary of Consolidated Revenues by Product and Service (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenue from External Customer [Line Items]
Sales of commodities	$ 1,858.1	$ 1,171
Fees from midstream services	254.5	271.4
Total revenues	2,112.6	1,442.4
Natural Gas Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities	480.9	326.9
NGL Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities	1,314.9	785.8
Condensate Sales [Member]
Revenue from External Customer [Line Items]
Sales of commodities	43.6	22.2
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sales of commodities	19.8	9.6
Derivative Activities [Member]
Revenue from External Customer [Line Items]
Sales of commodities	(1.1)	26.5
Fractionating and Treating Fees [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	31	30.2
Storage, Terminaling, Transportation and Export Fees [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	99.7	118.4
Gathering and Processing Fees [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	107.7	105
Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	$ 16.1	$ 17.8

Segment Information - Reconcili

Segment Information - Reconciliation of Operating Margin to Net Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reconciliation of operating margin to net income (loss):
Operating margin	$ 306.5	$ 299.3
Depreciation and amortization expenses	(191.1)	(193.5)
General and administrative expenses	(48.7)	(45.3)
Goodwill impairment	0	(24)
Interest expense, net	(63)	(52.9)
Other, net	(43.1)	18.8
Income tax (expense) benefit	(71.1)	(3.1)
Net income (loss)	$ (110.5)	$ (0.7)