Targa Resources Partners (NGLS-PA) 10-Q 3 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	Targa Resources Partners LP
Trading Symbol	NGLS
Entity Central Index Key	1,379,661
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 103.9	$ 68
Trade receivables, net of allowances of $0.1 and $0.9 million at September 30, 2017 and December 31, 2016	709.2	673.2
Inventories	267.4	137.7
Assets from risk management activities	18.7	16.8
Other current assets	80.5	31.5
Total current assets	1,179.7	927.2
Property, plant and equipment	13,685.2	12,511.9
Accumulated depreciation	(3,616.4)	(2,821)
Property, plant and equipment, net	10,068.8	9,690.9
Intangible assets, net	2,214.8	1,654
Goodwill, net	256.6	210
Long-term assets from risk management activities	13.7	5.1
Investments in unconsolidated affiliates	222.1	240.8
Other long-term assets	16.5	16.9
Total assets	13,972.2	12,744.9
Current liabilities:
Accounts payable and accrued liabilities	949.2	773.9
Accounts payable to Targa Resources Corp.	71.7	61
Liabilities from risk management activities	80.9	49.1
Current debt obligations	528.4	275
Total current liabilities	1,630.2	1,159
Long-term debt	3,933.6	4,177
Long-term liabilities from risk management activities	14.9	26.1
Deferred income taxes, net	26.9	26.9
Other long-term liabilities	484.9	205.3
Contingencies (see Note 16)
Owners' equity:
Series A preferred limited partners (5,000,000 and 5,000,000 units issued and 5,000,000 and 5,00,000 outstanding as of September 30, 2017 and December 31, 2016)	120.6	120.6
Common limited partners (275,168,410 and 275,168,410 units issued and 275,168,410 and 275,168,410 outstanding as of September 30, 2017 and December 31, 2016)	6,592.1	5,939.9
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of September 30, 2017 and December 31, 2016)	810.1	796.7
Accumulated other comprehensive income (loss)	(70.1)	(61.8)
Partners' Capital	7,452.7	6,795.4
Noncontrolling interests in subsidiaries	429	355.2
Total owners' equity	7,881.7	7,150.6
Total liabilities and owners' equity	$ 13,972.2	$ 12,744.9

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Trade receivables, allowances	$ 0.1	$ 0.9
Owners' equity:
Common limited partners units issued (in units)	275,168,410	275,168,410
Common limited partners units outstanding (in units)	275,168,410	275,168,410
General partner units issued (in units)	5,629,136	5,629,136
General partner units outstanding (in units)	5,629,136	5,629,136
Series A Preferred Limited Partner Units [Member]
Owners' equity:
Series A preferred limited partners units issued (in units)	5,000,000	5,000,000
Series A preferred limited partners units outstanding (in units)	5,000,000	5,000,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Sales of commodities	$ 1,871.5	$ 1,398.7	$ 5,353.1	$ 3,882.9
Fees from midstream services	260.3	253.6	759	795.5
Total revenues	2,131.8	1,652.3	6,112.1	4,678.4
Costs and expenses:
Product purchases	1,663.1	1,222.7	4,737.8	3,378.9
Operating expenses	155.5	143	462.6	413.9
Depreciation and amortization expense	208.3	184	602.8	563.6
General and administrative expense	46.6	44	139.4	132.3
Impairment of property, plant and equipment	378	0	378	0
Impairment of goodwill	0	0	0	24
Other operating (income) expense	0.6	4.9	17.2	6.1
Income (loss) from operations	(320.3)	53.7	(225.7)	159.6
Other income (expense):
Interest expense, net	(51.9)	(57.9)	(169.5)	(171.2)
Equity earnings (loss)	0.2	(2.2)	(16.6)	(11.4)
Gain (loss) from financing activities	0	0	(10.7)	21.4
Other, net	0.2	1	(2.7)	0.8
Change in contingent considerations	126.8	0.3	125.6	0.3
Income (loss) before income taxes	(245)	(5.1)	(299.6)	(0.5)
Income tax (expense) benefit	0	(1)	4.2	0
Net income (loss)	(245)	(6.1)	(295.4)	(0.5)
Less: Net income attributable to noncontrolling interests	9.7	4.7	25.9	13.5
Net income (loss) attributable to Targa Resources Partners LP	(254.7)	(10.8)	(321.3)	(14)
Net income attributable to preferred limited partners	2.8	2.8	8.4	8.4
Net income (loss) attributable to general partner	(5.2)	29	(6.6)	68.2
Net income (loss) attributable to common limited partners	(252.3)	(42.6)	(323.1)	(90.6)
Net income (loss) attributable to Targa Resources Partners LP	$ (254.7)	$ (10.8)	$ (321.3)	$ (14)

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net income (loss)	$ (245)	$ (6.1)	$ (295.4)	$ (0.5)
Other comprehensive income (loss):
Other comprehensive income (loss)	(104.7)	4.8	(8.3)	(91.1)
Comprehensive income (loss)	(349.7)	(1.3)	(303.7)	(91.6)
Less: Comprehensive income attributable to noncontrolling interests	9.7	4.7	25.9	13.5
Comprehensive income (loss) attributable to Targa Resources Partners LP	(359.4)	(6)	(329.6)	(105.1)
Commodity Contracts [Member]
Other comprehensive income (loss):
Settlements reclassified to net income	2.1	(8.1)	2.2	(50.6)
Change in fair value	$ (106.8)	$ 12.9	$ (10.5)	$ (40.5)

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - USD ($) shares in Thousands, $ in Millions	Total	Limited Partner Preferred [Member]	Limited Partners Common [Member]	General Partner Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Units [Member]	Non-controlling Interests [Member]
Balance at Dec. 31, 2015	$ 6,902.9	$ 120.6	$ 4,550.4	$ 1,735.3	$ 86.8	$ (10.3)	$ 420.1
Balance (in units) at Dec. 31, 2015		5,000	184,871	3,773		212
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	2.2	$ 0	$ 2.2	$ 0	0	$ 0	0
Compensation on equity grants (in units)		0	0	0		0
Distribution equivalent rights	(0.2)	$ 0	$ (0.2)	$ 0	0	$ 0	0
Issuance of common units under compensation program	0	$ 0	$ 0	$ 0	0	$ 0	0
Issuance of common units under compensation program (in units)		0	30	0		0
Units tendered for tax withholding obligations	(0.1)	$ 0	$ 0	$ 0	0	$ (0.1)	0
Units tendered for tax withholding obligations (in units)		0	(1)	0		1
Cancellation of treasury units	0	$ 0	$ (10.2)	$ (0.2)	0	$ 10.4	0
Cancellation of treasury units (in units)		0	0	0		(213)
Contributions from Targa Resources Corp.	1,191	$ 0	$ 1,167.2	$ 23.8	0	$ 0	0
Contributions from Targa Resources Corp. (in units)		0	58,621	1,197		0
Distributions to noncontrolling interests	(16.8)	$ 0	$ 0	$ 0	0	$ 0	(16.8)
Contributions from noncontrolling interests	32.7	0	0	0	0	0	32.7
Other comprehensive income (loss)	(91.1)	0	0	0	(91.1)	0	0
Net income (loss)	(0.5)	8.4	(90.6)	68.2	0	0	13.5
Distributions	(542.6)	(8.4)	(440.2)	(94)	0	0	0
Balance at Sep. 30, 2016	7,477.5	$ 120.6	$ 5,178.6	$ 1,733.1	(4.3)	$ 0	449.5
Balance (in units) at Sep. 30, 2016		5,000	243,521	4,970		0
Balance at Dec. 31, 2016	7,150.6	$ 120.6	$ 5,939.9	$ 796.7	(61.8)	$ 0	355.2
Balance (in units) at Dec. 31, 2016		5,000	275,168	5,629		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Targa Resources Corp.	1,620	$ 0	$ 1,587.5	$ 32.5	0	$ 0	0
Contributions from Targa Resources Corp. (in units)		0	0	0		0
Purchase of noncontrolling interests in subsidiary	(12.5)	$ 0	$ 0	$ 0	0	$ 0	(12.5)
Distributions to noncontrolling interests	(33.4)	0	0	0	0	0	(33.4)
Contributions from noncontrolling interests	93.8	0	0	0	0	0	93.8
Other comprehensive income (loss)	(8.3)	0	0	0	(8.3)	0	0
Net income (loss)	(295.4)	8.4	(323.1)	(6.6)	0	0	25.9
Distributions	(633.1)	(8.4)	(612.2)	(12.5)	0	0	0
Balance at Sep. 30, 2017	$ 7,881.7	$ 120.6	$ 6,592.1	$ 810.1	$ (70.1)	$ 0	$ 429
Balance (in units) at Sep. 30, 2017		5,000	275,168	5,629		0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities
Net income (loss)		$ (295.4)	$ (0.5)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		7.1	9.8
Compensation on equity grants		0	2.2
Depreciation and amortization expense		602.8	563.6
Impairment of property, plant and equipment		378	0
Impairment of goodwill		0	24
Accretion of asset retirement obligations		3	3.5
Increase (decrease) in redemption value of mandatorily redeemable preferred interests		8.5	(18.8)
Equity (earnings) loss of unconsolidated affiliates		16.6	11.4
Distributions of earnings received from unconsolidated affiliates		8.4	1.8
Risk management activities		13.9	11.7
(Gain) loss on sale or disposition of assets	[1]	16.6	5.7
(Gain) loss from financing activities		10.7	(21.4)
Change in contingent considerations included in Other expense (income)		(125.6)	(0.3)
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		(91.5)	(28.3)
Inventories		(136.4)	(27.8)
Accounts payable and other liabilities		46.5	32.1
Net cash provided by operating activities		463.2	568.7
Cash flows from investing activities
Outlays for property, plant and equipment		(866.6)	(425)
Outlays for business acquisition, net of cash acquired		(570.8)	0
Investments in unconsolidated affiliates		(7.5)	(4.6)
Return of capital from unconsolidated affiliates		2.2	3.4
Other, net		(14.8)	4.2
Net cash used in investing activities		(1,457.5)	(422)
Debt obligations:
Proceeds from borrowings under credit facility		1,496	1,110
Repayments of credit facility		(1,216)	(1,390)
Proceeds from borrowings under accounts receivable securitization facility		281.6	121.4
Repayments of accounts receivable securitization facility		(278.5)	(115.7)
Open market purchases of senior notes		0	(534.3)
Redemption of senior notes		(287.6)	0
Costs incurred in connection with financing arrangements		(0.1)	(7.5)
Repurchase of common units under compensation plans		0	(0.1)
Purchase of noncontrolling interests in subsidiary		(12.5)	0
Contributions from general partner		32.5	23.8
Contributions from TRC		1,587.5	1,167.2
Contributions from noncontrolling interests		93.8	32.7
Distributions to noncontrolling interests		(33.4)	(16.8)
Distributions to unitholders		(633.1)	(542.6)
Payments of distribution equivalent rights		0	(0.3)
Net cash provided by (used in) financing activities		1,030.2	(152.2)
Net change in cash and cash equivalents		35.9	(5.5)
Cash and cash equivalents, beginning of period		68	135.4
Cash and cash equivalents, end of period		$ 103.9	$ 129.9
[1]	Comprised primarily of a $16.1 million loss in the first quarter of 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	9 Months Ended
	Sep. 30, 2017
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract]
Organization and Operations	Note 1 — Organization and Operations Our Organization Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transactions, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its 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. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.” On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable. Our Operations We are engaged in the business of: • gathering, compressing, treating, processing and selling natural gas; • storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; • gathering, storing, terminaling and selling crude oil; and • storing, terminaling and selling refined petroleum products. See Note 19 – Segment Information for certain financial information regarding our business segments. The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 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 and nine months ended September 30, 2017 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 and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the full year.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies Accounting Policy Updates The accounting 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 , 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 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 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs. We have disaggregated contracts within our two segments and are in the process of completing our review of 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. Gathering and Processing Segment Based on our progress to date, we have preliminarily concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream are contracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updated guidance in ASC 705, Cost of Sales and Services Specifically, when such arrangements contain both a service revenue element and a supply element, we are in the process of determining how each element should be measured. Logistics and Marketing Segment At this time, we are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment, although the potential effects of contributions in aid of construction (which may also affect certain Gathering and Processing contracts where we are acting as an agent for the producer), tiered pricing, and excess fuel are currently being evaluated. We are also anticipating additional disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the current reporting period, separate presentation of revenue from contracts with customers and non-customer revenue (i.e. the effects of derivative activity and lease revenue) as well as unbilled receivables and deferred revenue. The new revenue recognition standard is effective for us on January 1, 2018, and currently we plan to adopt using the modified retrospective method and will recognize a cumulative effect adjustment, if any, in the first quarter of 2018. However, we will continue to evaluate our planned adoption method based on our views regarding stakeholder needs and a final determination on remaining accounting matters still under evaluation. We have also established a cross-functional team to assist with the implementation through documentation of process changes, identification of implementation risks, update and development of mitigating controls, determination of data requirements, and identification of changes in system mapping and configuration. Leases In February 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 In October Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory Business In January Business Combinations (Topic 805): Clarifying the Definition of a Business Impairment of Goodwill In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would have been impaired. We expect to apply these amendments for our annual goodwill impairment test as of November 30, which may result in impairment of goodwill for 2017. Other Income In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) These amendments are 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 such amendments on our consolidated financial statements. Stock Compensation – Scope of Modification Accounting In May Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting Financial Instruments with Down Round Features In July 2017, FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception Targeted Improvements to Accounting for Hedge Activities In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 4 – Acquisitions and Divestitures 2017 Acquisitions 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 paid an additional $90.0 million in cash on May 30, 2017 (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 would 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, and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/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 MBbl/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 the New Midland’s gas gathering and processing assets were connected to our existing WestTX system in October 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, Targa completed a public offering of 9,200,000 shares of its 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. Targa 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 $75.2 million and a net loss of $21.5 million to us for the period from March 1, 2017 to September 30, 2017, and are reported in our Gathering and Processing segment. As of September 30, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the nine months ended September 30, 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 nine months ended September 30, 2017 and September 30, 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. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Pro Forma Pro Forma Pro Forma Pro Forma Revenues $ 2,131.8 $ 1,663.0 $ 6,126.2 $ 4,697.3 Net income (loss) (244.7 ) (18.3 ) (297.0 ) (44.7 ) 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 fair value of intangible assets recognized as part of the Permian Acquisition. • 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 fair value of property, plant and equipment acquired. • Exclude $5.6 million of acquisition-related costs incurred as of September 30, 2017 from pro forma net income for the nine months ended September 30, 2017. Pro forma net income for the nine months ended September 30, 2016 was adjusted to include those charges. The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of $3.3 million cash acquired $ 570.8 Contingent consideration valuation as of the acquisition date 416.3 Total $ 987.1 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 value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination (final): March 1, 2017 Trade and other current receivables, net $ 6.7 Other current assets 0.6 Property, plant and equipment 255.8 Intangible assets 692.3 Current liabilities (14.1 ) Other long-term liabilities (0.8 ) Total identifiable net assets 940.5 Goodwill 46.6 Total fair value of assets acquired and liabilities assumed $ 987.1 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 fair value of assets acquired included trade receivables of $6.7 million, substantially all of which has been subsequently collected. 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. During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments. Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that would occur in 2018 and 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the fair value of this liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the three and nine months ended September 30, 2017, we recognized $126.6 million and $125.5 million as Other income related to the change in fair value of the contingent consideration. See Note 11 – Other Long-term Liabilities and Note 14 – Fair Value Measurements for additional discussion of the change in fair value and the fair value methodology. As of September 30, 2017, the fair value of the first potential earn-out payment of $5.9 million has been recorded as a component of Accounts payable and accrued liabilities, which are included within current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. Flag City Acquisition On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCCP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights-of-ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts. The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak Plants. We have shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations. We accounted for this purchase as an asset acquisition and have capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net. Purchase of Outstanding Silver Oak II Interest Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) their 10% interest in our consolidated Silver Oak II Gas processing facility and other related assets located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result. 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 Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in 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”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. As a result of the April 4, 2017 sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the three months ended March 31, 2017 as part of Other operating (income) expense to impair our basis in the VGS net assets to its fair value. 2017 Joint Venture Grand Prix Joint Venture In May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third party customer commitments, and is expected to be in service in the second quarter of 2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. In September 2017, we sold to funds managed by Blackstone Energy Partners ("Blackstone") a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”). total growth capital expenditures for Grand Prix is expected to be approximately $975 million, with approximately $275 million of spending in 2017. Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement for transportation and fractionation whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories September 30, 2017 December 31, 2016 Commodities $ 255.6 $ 126.9 Materials and supplies 11.8 10.8 $ 267.4 $ 137.7

Property, Plant and Equipment a

Property, Plant and Equipment and Intangible Assets	9 Months Ended
	Sep. 30, 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 September 30, 2017 December 31, 2016 Estimated Useful Lives (In Years) Gathering systems $ 6,900.8 $ 6,626.9 5 to 20 Processing and fractionation facilities 3,571.3 3,383.6 5 to 25 Terminaling and storage facilities 1,238.0 1,205.0 5 to 25 Transportation assets 343.2 451.4 10 to 25 Other property, plant and equipment 284.7 274.0 3 to 25 Land 123.8 121.2 — Construction in progress 1,223.4 449.8 — Property, plant and equipment 13,685.2 12,511.9 Accumulated depreciation (3,616.4 ) (2,821.0 ) Property, plant and equipment, net $ 10,068.8 $ 9,690.9 Intangible assets $ 2,736.6 $ 2,036.6 10 to 20 Accumulated amortization (521.8 ) (382.6 ) Intangible assets, net $ 2,214.8 $ 1,654.0 Impairment of North Texas Gathering and Processing Assets We recorded a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017 for the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment is a result of our current assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows are based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis is based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment expense in our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian and Flag City Acquisitions 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. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. The intangible assets acquired in the Permian Acquisition were recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life using the straight-line method. The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method. 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 is approximately $188.4 million, $182.6 million, $171.6 million, $159.4 million and $149.5 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 692.3 Additions from Flag City Acquisition 7.7 Amortization (139.2 ) Balance at September 30, 2017 $ 2,214.8

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 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 in 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 — — 46.6 46.6 Balance at September 30, 2017, net $ 174.7 $ 35.3 $ 46.6 $ 256.6

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2017
Equity Method Investments And Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Note 8 – Investments in Unconsolidated Affiliates Our investments in unconsolidated affiliates consist of the following: • a • 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”); and • a 50% operated ownership interest in Cayenne Pipeline, LLC (“Cayenne ”). 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 The T2 Joint Ventures were formed to provide services for the benefit of its joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with its joint interest owners, which cover costs of operations (excluding depreciation and amortization). In July 2017, we entered into the Cayenne with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne . The project is expected to be completed by November 2017. The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Cayenne Total Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ — $ 240.8 Equity earnings (loss) 8.4 (3.7 ) (7.9 ) (13.4 ) — (16.6 ) Cash distributions (1) (10.6 ) — — — — (10.6 ) Acquisition — — — — 5.0 5.0 Contributions (2) — 0.4 1.2 0.1 1.8 3.5 Balance at September 30, 2017 $ 43.9 $ 55.3 $ 111.9 $ 4.2 $ 6.8 $ 222.1 (1) Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2017. 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) Our equity loss for the nine months ended September 30, 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 occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers. The carrying values of the T2 Joint Venture Subsequent Event Gulf Coast Express Joint Venture In October 2017, we announced that we had executed a letter of intent along with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP with respect to the joint development of the proposed Gulf Coast Express Pipeline Project (“GCX Project”), which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the letter of intent, we would own a 25% interest in the GCX Project. KMTP would serve as the operator and constructor of the GCX Project, and we would commit significant volumes to it, including certain volumes provided by Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system. The participation of the three parties involved with GCX Project is subject to negotiation and execution of definitive agreements.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	9 Months Ended
	Sep. 30, 2017
Payables And Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 — Accounts Payable and Accrued Liabilities September 30, 2017 December 31, 2016 Commodities $ 600.9 $ 574.5 Other goods and services 220.5 113.4 Interest 48.7 52.2 Permian Acquisition contingent consideration, estimated current portion 5.9 — Income and other taxes 57.3 19.1 Other 15.9 14.7 $ 949.2 $ 773.9 Accounts payable and accrued liabilities includes $29.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remained outstanding as of September 30, 2017 and December 31, 2016. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value as of September 30, 2017 of the first potential earn-out payment that would be payable in May 2018. The estimated remaining portion would be payable in May 2019 and is recorded within Other long-term liabilities on our Consolidated Balance Sheets.

Debt Obligations

Debt Obligations	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Debt Obligations	Note 10 — Debt Obligations September 30, 2017 December 31, 2016 Current: Accounts receivable securitization facility, due December 2017 $ 278.1 $ 275.0 Senior unsecured notes, 5% fixed rate, due January 2018 (1) 250.5 — 528.6 275.0 Debt issuance costs, net of amortization (0.2 ) — Current debt obligations 528.4 275.0 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (2) 430.0 150.0 Senior unsecured notes: 5% fixed rate, due January 2018 (1) — 250.5 4⅛% fixed rate, due November 2019 749.4 749.4 6⅜% fixed rate, due August 2022 — 278.7 5¼% fixed rate, due May 2023 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 (3) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 48.1 Unamortized premium 0.4 0.5 3,958.0 4,207.3 Debt issuance costs, net of amortization (24.4 ) (30.3 ) Long-term debt 3,933.6 4,177.0 Total debt obligations $ 4,462.0 $ 4,452.0 Irrevocable standby letters of credit outstanding $ 22.4 $ 13.2 (1) The 5% Notes (“5% Senior Notes due 2018”) were reclassified to a current liability in January 2017. Prior to that date, the notes were classified as a long-term liability on our Consolidated Balance Sheets. These notes were redeemed on October 30, 2017. (2) As of September 30, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,147.6 million. (3) Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2017: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.0% - 5.3% 3.2% Accounts receivable securitization facility 1.8% - 2.2% 2.0% Compliance with Debt Covenants As of September 30, 2017, we were in compliance with the covenants contained in our various debt agreements. Securitization Facility On February 23, 2017, we amended the accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million. As of September 30, 2017, there was $278.1 million outstanding under the Securitization Facility. Debt Repurchases & Extinguishments In June 2017, we redeemed our outstanding 6⅜% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling $278.7 million in aggregate principal amount, at a price of 103.188% plus accrued interest through the redemption date. The redemption resulted in a $10.7 million loss, which is reflected as Loss from financing activities in the Consolidated Statements of Operations, consisting of premiums paid of $8.9 million and a non-cash loss to write-off $1.8 million of unamortized debt issuance costs. Subsequent Events In October 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”). We used the net proceeds of $744.4 million after costs from this offering to redeem our 5% Senior Notes due 2018, reduce borrowings under our credit facilities, and for general partnership purposes. In October 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value

Other Long-term Liabilities

Other Long-term Liabilities	9 Months Ended
	Sep. 30, 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: September 30, 2017 December 31, 2016 Asset retirement obligations $ 49.4 $ 64.1 Mandatorily redeemable preferred interests 80.0 68.5 Deferred revenue 67.5 69.8 Permian Acquisition contingent consideration, noncurrent portion 284.9 — Other liabilities 3.1 2.9 Total long-term liabilities $ 484.9 $ 205.3 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 $ 64.1 Additions (1) 0.8 Reduction due to sale of VGS (21.6 ) Change in cash flow estimate 3.1 Accretion expense 3.0 Balance at September 30, 2017 $ 49.4 _____________________________________________________________________________________________________________________________________________________________ (1) Amount reflects ARO 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 cannot occur before 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 September 30, 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 3.0 Change in estimated redemption value included in interest expense 8.5 Balance at September 30, 2017 $ 80.0 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 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 nonmonetary 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 gathering 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: September 30, 2017 December 31, 2016 Splitter agreement $ 43.0 $ 43.0 Gas contract amendment 18.6 19.7 Other deferred revenue 5.9 7.1 Total deferred revenue $ 67.5 $ 69.8 The following table shows the changes in deferred revenue: Balance at December 31, 2016 $ 69.8 Additions — Revenue recognized (2.3 ) Balance at September 30, 2017 $ 67.5 Contingent Consideration Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. The potential earn-out payments will be based upon a multiple of gross margin realized during the first two annual periods after the acquisition date During the three months ended June 30, 2017, we recognized certain adjustments that were accounted for as revisions to the acquisition date fair value and decreased the acquisition date fair value of the contingent consideration by $45.3 million to $416.3 million. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional revisions to the acquisition date fair value. See Note 4 – Acquisitions and Divestments for additional discussion. For the period from the acquisition date to September 30, 2017, the fair value of this liability decreased by $125.5 million, bringing the total Permian Acquisition contingent consideration to $290.8 million at September 30, 2017. The decrease in fair value of the contingent consideration was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstances that occurred after the acquisition date, and as such have been recognized in Other income (expense). As of September 30, 2017, the fair value of the first potential earn-out payment of $5.9 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology. The following table shows the changes in contingent consideration: Balance at March 1, 2017 (acquisition date) $ 461.6 Measurement period adjustment of acquisition date value (45.3 ) Decrease in fair value due to factors occurring after acquisition date (125.5 ) Balance at September 30, 2017 290.8 Less: Current portion (5.9 ) Long-term balance at September 30, 2017 $ 284.9

Partnership Units and Related M

Partnership Units and Related Matters	9 Months Ended
	Sep. 30, 2017
Partners Capital [Abstract]
Partnership Units and Related Matters	Note 12 — Partnership Units and Related Matters Distributions As a result of the TRC/TRP Merger, TRC is entitled to receive all Partnership distributions from available cash on the Partnership’s common units after payment of preferred units distributions each quarter. We have discretion under the Third A&R Partnership Agreement See Note 1 – Organization and Operations. The following details the distributions declared or paid by us for the nine months ended September 30, 2017: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. September 30, 2017 November 10, 2017 $ 225.4 $ 222.6 June 30, 2017 August 10, 2017 225.4 222.6 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 us, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. For the nine months ended September 30, 2017, TRC made total capital contributions to us of $1,620.0 million. Preferred Units In October 2015, we 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.” At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement. Distributions on our 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 our general partner. Distributions on our 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 our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. We paid $2.8 million and $8.4 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three and nine months ended September 30, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements. Subsequent Event In October 2017, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on November 15, 2017.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 13 — 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, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements and (ii) future commodity purchases and sales in our Logistics and Marketing segment by entering into derivative instruments. 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 $1.4 million and $6.3 million for the three and nine months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received derivative settlements of $100.9 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 and $0.1 million for the three and nine months ended September 30, 2017 and less than $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps. 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 September 30, 2017, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 2020 Natural Gas Swaps MMBtu/d 160,347 151,100 116,136 - Natural Gas Basis Swaps MMBtu/d 92,200 15,726 12,500 10,445 Natural Gas Futures MMBtu/d - 1,103 - - Natural Gas Options MMBtu/d 22,900 9,486 - - NGL Swaps Bbl/d 23,432 12,858 7,399 - NGL Futures Bbl/d 38,880 6,589 329 - NGL Options Bbl/d 3,094 2,986 410 - Condensate Swaps Bbl/d 3,150 2,420 1,293 - 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 on 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 September 30, 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 $ 18.4 $ 79.9 $ 16.7 $ 48.6 Long-term 13.7 14.4 5.1 26.1 Total derivatives designated as hedging instruments $ 32.1 $ 94.3 $ 21.8 $ 74.7 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.3 $ 1.0 $ 0.1 $ 0.5 Long-term - 0.5 - - Total derivatives not designated as hedging instruments $ 0.3 $ 1.5 $ 0.1 $ 0.5 Total current position $ 18.7 $ 80.9 $ 16.8 $ 49.1 Total long-term position 13.7 14.9 5.1 26.1 Total derivatives $ 32.4 $ 95.8 $ 21.9 $ 75.2 The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation September 30, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 18.7 $ (79.5 ) $ 44.6 $ 3.6 $ (19.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (1.4 ) - - (1.4 ) 18.7 (80.9 ) 44.6 3.6 (21.2 ) Long Term Position Counterparties with offsetting positions or collateral 13.5 (14.2 ) - 6.5 (7.2 ) Counterparties without offsetting positions - assets 0.2 - - 0.2 - Counterparties without offsetting positions - liabilities - (0.7 ) - - (0.7 ) 13.7 (14.9 ) - 6.7 (7.9 ) Total Derivatives Counterparties with offsetting positions or collateral 32.2 (93.7 ) 44.6 10.1 (27.0 ) Counterparties without offsetting positions - assets 0.2 - - 0.2 - Counterparties without offsetting positions - liabilities - (2.1 ) - - (2.1 ) $ 32.4 $ (95.8 ) $ 44.6 $ 10.3 $ (29.1 ) 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 our 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 liability of $63.4 million as of September 30, 2017. The estimated fair value is net of an adjustment for credit risk based on the default probabilities 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 September 30, Nine Months Ended September 30, Hedging Relationships 2017 2016 2017 2016 Commodity contracts $ (106.8 ) $ 12.9 $ (10.5 ) $ (40.5 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended September 30, Nine Months Ended September 30, Location of Gain (Loss) 2017 2016 2017 2016 Revenues $ (2.1 ) $ 8.1 $ (2.2 ) $ 50.6 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 September 30, Nine Months Ended September 30, as Hedging Instruments Derivatives 2017 2016 2017 2016 Commodity contracts Revenue $ (1.5 ) $ (0.3 ) $ (2.9 ) $ 1.3 Based on valuations as of September 30, 2017, we expect to reclassify commodity hedge-related deferred losses of $64.1 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $63.0 million of losses to be reclassified over the next twelve months. See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 14 — Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on 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 September 30, 2017, a net liability position of $63.4 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 $149.9 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 $22.2 million, ignoring an adjustment for counterparty credit risk. Fair Value of Other Financial Instruments Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: • The TRP Revolver and the accounts receivable securitization facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and • Senior unsecured notes are based on quoted market prices derived from trades of the debt. 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 on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: September 30, 2017 Fair Value Carrying 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) $ 32.0 $ 32.0 $ — $ 29.0 $ 3.0 Liabilities from commodity derivative contracts (1) 95.4 95.4 — 86.5 8.9 Permian Acquisition contingent consideration (2) 290.8 290.8 — — 290.8 TPL contingent consideration (3) 2.5 2.5 — — 2.5 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 103.9 103.9 — — — TRP Revolver 430.0 430.0 — 430.0 — Senior unsecured notes 3,778.5 3,881.2 — 3,881.2 — Accounts receivable securitization facility 278.1 278.1 — 278.1 — December 31, 2016 Fair Value Carrying 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 Permian Acquisition contingent consideration (2) — — — — — 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 68.0 68.0 — — — TRP Revolver 150.0 150.0 — 150.0 — Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — 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 13 – 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, which is carried at fair value. See Note 4 – Acquisitions and Divestitures. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. Additional Information Regarding Level 3 Fair Value Measurements Included on 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 September 30, 2017, we had 31 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) in 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) - (290.8 ) New Level 3 derivative instruments (0.8 ) - Transfers out of Level 3 (2) 1.6 - Settlements included in Revenue 0.4 - Unrealized gain/(loss) included in OCI (3.5 ) - Balance, September 30, 2017 $ (5.9 ) $ (293.3 ) (1) Represents the September 30, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 –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.

Related Party Transactions - Ta

Related Party Transactions - Targa	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions - Targa	Note 15 — Related Party Transactions - Targa Relationship with Targa We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay. The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Targa billings of payroll and related costs included in operating expense $ 54.0 $ 42.6 $ 148.6 $ 125.0 Targa allocation of general and administrative expense 43.2 40.1 126.6 117.7 Cash distributions to Targa based on IDR, general partner and limited partner ownership (1) 222.6 178.9 624.7 395.1 Cash contributions from Targa related to limited partner ownership (2) 14.7 210.7 1,587.5 1,167.2 Cash contributions from Targa to maintain its 2% general partner ownership 0.3 4.3 32.5 23.8 _______________________ (1) As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on general partner and limited partner ownership. (2) The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 12 – Partnership Units and Related Matters.

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2017
Loss Contingency [Abstract]
Contingencies	Note 16 – Contingencies Legal Proceedings We are a party 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	9 Months Ended
	Sep. 30, 2017
Other Income And Expenses [Abstract]
Other Operating (Income) Expense	Note 17 – Other Operating (Income) Expense Other operating (income) expense is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Loss on sale or disposal of assets (1) $ 0.3 $ 4.7 $ 16.6 $ 5.7 Miscellaneous business tax 0.3 0.2 0.6 0.4 $ 0.6 $ 4.9 $ 17.2 $ 6.1 __________________________________________________________________________________________________ (1) Comprised primarily of a $16.1 million loss in the first quarter of 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	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 18 — Supplemental Cash Flow Information Nine Months Ended September 30, 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 154.5 $ 197.1 Income taxes paid, net of refunds (4.9 ) 1.2 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 118.3 (0.5 ) Transfers from materials and supplies inventory to property, plant and equipment 2.8 1.9 Contribution of property, plant and equipment to investments in unconsolidated affiliates 1.0 — Change in ARO liability and property, plant and equipment due to revised cash flow estimate 3.1 (9.2 ) Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ 416.3 $ — Non-cash financing activities: Cancellation of treasury units $ — $ (10.4 ) Accrued distributions on unvested equity awards under share compensation arrangements — 0.2 _____________ (1) Interest capitalized on major projects was $8.3 million and $7.2 million for the nine months ended September 30, 2017 and 2016.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information	Note 19 — 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. The Logistics and Marketing segment also includes our Grand Prix project. 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, Galena Park and Channelview, 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 September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 200.3 $ 1,672.2 $ (1.0 ) $ — $ 1,871.5 Fees from midstream services 148.5 111.8 — — 260.3 348.8 1,784.0 (1.0 ) — 2,131.8 Intersegment revenues Sales of commodities 783.7 80.6 — (864.3 ) — Fees from midstream services 1.7 7.0 — (8.7 ) — 785.4 87.6 — (873.0 ) — Revenues $ 1,134.2 $ 1,871.6 $ (1.0 ) $ (873.0 ) $ 2,131.8 Operating margin $ 198.3 $ 115.9 $ (1.0 ) $ — * Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 295.9 $ 71.0 $ — $ 11.8 $ 378.7 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Three Months Ended September 30, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 172.2 $ 1,215.3 $ 11.2 $ — $ 1,398.7 Fees from midstream services 120.6 133.0 — — 253.6 292.8 1,348.3 11.2 — 1,652.3 Intersegment revenues Sales of commodities 574.8 76.3 — (651.1 ) — Fees from midstream services 1.9 6.6 — (8.5 ) — 576.7 82.9 — (659.6 ) — Revenues $ 869.5 $ 1,431.2 $ 11.2 $ (659.6 ) $ 1,652.3 Operating margin $ 149.4 $ 126.0 $ 11.2 $ — * Other financial information: Total assets (1) $ 10,047.3 $ 2,737.5 $ 47.2 $ 76.2 $ 12,908.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 97.1 $ 36.2 $ — $ 1.3 $ 134.6 ____________________________________________________________________________________________ (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Nine Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 544.4 $ 4,804.8 $ 3.9 $ — $ 5,353.1 Fees from midstream services 399.3 359.7 — — 759.0 943.7 5,164.5 3.9 — 6,112.1 Intersegment revenues Sales of commodities 2,209.2 237.8 — (2,447.0 ) — Fees from midstream services 5.1 21.1 — (26.2 ) — 2,214.3 258.9 — (2,473.2 ) — Revenues $ 3,158.0 $ 5,423.4 $ 3.9 $ (2,473.2 ) $ 6,112.1 Operating margin $ 549.3 $ 358.5 $ 3.9 $ — * Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 730.7 $ 241.8 $ — $ 15.2 $ 987.7 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 _____________________________________________________________________________________________ (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Nine Months Ended September 30, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 441.3 $ 3,384.7 $ 56.9 $ — $ 3,882.9 Fees from midstream services 360.9 434.6 — — 795.5 802.2 3,819.3 56.9 — 4,678.4 Intersegment revenues Sales of commodities 1,455.8 176.3 — (1,632.1 ) — Fees from midstream services 5.8 15.1 — (20.9 ) — 1,461.6 191.4 — (1,653.0 ) — Revenues $ 2,263.8 $ 4,010.7 $ 56.9 $ (1,653.0 ) $ 4,678.4 Operating margin $ 404.1 $ 424.6 $ 56.9 $ — * Other financial information: Total assets (1) $ 10,047.3 $ 2,737.5 $ 47.2 $ 76.2 $ 12,908.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 271.3 $ 151.9 $ — $ 3.3 $ 426.5 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Sales of commodities: Natural gas $ 504.1 $ 465.6 $ 1,480.9 $ 1,102.0 NGL 1,274.9 866.7 3,623.9 2,575.8 Condensate 44.9 35.0 135.9 96.2 Petroleum products 48.6 20.2 108.5 52.0 Derivative activities (1.0 ) 11.2 3.9 56.9 1,871.5 1,398.7 5,353.1 3,882.9 Fees from midstream services: Fractionating and treating 29.8 33.2 92.8 94.8 Storage, terminaling, transportation and export 75.0 89.7 247.8 316.3 Gathering and processing 138.0 110.9 368.5 329.9 Other 17.5 19.8 49.9 54.5 260.3 253.6 759.0 795.5 Total revenues $ 2,131.8 $ 1,652.3 $ 6,112.1 $ 4,678.4 The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 198.3 $ 149.4 $ 549.3 $ 404.1 Logistics and Marketing operating margin 115.9 126.0 358.5 424.6 Other operating margin (1.0 ) 11.2 3.9 56.9 Depreciation and amortization expenses (208.3 ) (184.0 ) (602.8 ) (563.6 ) General and administrative expenses (46.6 ) (44.0 ) (139.4 ) (132.3 ) Impairment of property, plant and equipment (378.0 ) — (378.0 ) — Impairment of goodwill — — — (24.0 ) Interest expense, net (51.9 ) (57.9 ) (169.5 ) (171.2 ) Other, net 126.6 (5.8 ) 78.4 5.0 Income (loss) before income taxes $ (245.0 ) $ (5.1 ) $ (299.6 ) $ (0.5 )

Significant Accounting Polici27

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 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 , 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 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 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs. We have disaggregated contracts within our two segments and are in the process of completing our review of 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. Gathering and Processing Segment Based on our progress to date, we have preliminarily concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream are contracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updated guidance in ASC 705, Cost of Sales and Services Specifically, when such arrangements contain both a service revenue element and a supply element, we are in the process of determining how each element should be measured. Logistics and Marketing Segment At this time, we are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment, although the potential effects of contributions in aid of construction (which may also affect certain Gathering and Processing contracts where we are acting as an agent for the producer), tiered pricing, and excess fuel are currently being evaluated. We are also anticipating additional disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the current reporting period, separate presentation of revenue from contracts with customers and non-customer revenue (i.e. the effects of derivative activity and lease revenue) as well as unbilled receivables and deferred revenue. The new revenue recognition standard is effective for us on January 1, 2018, and currently we plan to adopt using the modified retrospective method and will recognize a cumulative effect adjustment, if any, in the first quarter of 2018. However, we will continue to evaluate our planned adoption method based on our views regarding stakeholder needs and a final determination on remaining accounting matters still under evaluation. We have also established a cross-functional team to assist with the implementation through documentation of process changes, identification of implementation risks, update and development of mitigating controls, determination of data requirements, and identification of changes in system mapping and configuration. Leases In February 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 In October Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory Business In January Business Combinations (Topic 805): Clarifying the Definition of a Business Impairment of Goodwill In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would have been impaired. We expect to apply these amendments for our annual goodwill impairment test as of November 30, which may result in impairment of goodwill for 2017. Other Income In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) These amendments are 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 such amendments on our consolidated financial statements. Stock Compensation – Scope of Modification Accounting In May Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting Financial Instruments with Down Round Features In July 2017, FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception Targeted Improvements to Accounting for Hedge Activities In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Pro Forma Consolidated Information of Operations	The following summarized unaudited pro forma Consolidated Statement of Operations information for the nine months ended September 30, 2017 and September 30, 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. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Pro Forma Pro Forma Pro Forma Pro Forma Revenues $ 2,131.8 $ 1,663.0 $ 6,126.2 $ 4,697.3 Net income (loss) (244.7 ) (18.3 ) (297.0 ) (44.7 )
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 $3.3 million cash acquired $ 570.8 Contingent consideration valuation as of the acquisition date 416.3 Total $ 987.1
Fair Value of the Assets and Liabilities Assumed at Acquisition Date	The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination (final): March 1, 2017 Trade and other current receivables, net $ 6.7 Other current assets 0.6 Property, plant and equipment 255.8 Intangible assets 692.3 Current liabilities (14.1 ) Other long-term liabilities (0.8 ) Total identifiable net assets 940.5 Goodwill 46.6 Total fair value of assets acquired and liabilities assumed $ 987.1

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Components of Inventories	September 30, 2017 December 31, 2016 Commodities $ 255.6 $ 126.9 Materials and supplies 11.8 10.8 $ 267.4 $ 137.7

Property, Plant and Equipment30

Property, Plant and Equipment and Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2017
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	September 30, 2017 December 31, 2016 Estimated Useful Lives (In Years) Gathering systems $ 6,900.8 $ 6,626.9 5 to 20 Processing and fractionation facilities 3,571.3 3,383.6 5 to 25 Terminaling and storage facilities 1,238.0 1,205.0 5 to 25 Transportation assets 343.2 451.4 10 to 25 Other property, plant and equipment 284.7 274.0 3 to 25 Land 123.8 121.2 — Construction in progress 1,223.4 449.8 — Property, plant and equipment 13,685.2 12,511.9 Accumulated depreciation (3,616.4 ) (2,821.0 ) Property, plant and equipment, net $ 10,068.8 $ 9,690.9 Intangible assets $ 2,736.6 $ 2,036.6 10 to 20 Accumulated amortization (521.8 ) (382.6 ) Intangible assets, net $ 2,214.8 $ 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 692.3 Additions from Flag City Acquisition 7.7 Amortization (139.2 ) Balance at September 30, 2017 $ 2,214.8

Goodwill (Tables)

Goodwill (Tables)	9 Months Ended
	Sep. 30, 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 — — 46.6 46.6 Balance at September 30, 2017, net $ 174.7 $ 35.3 $ 46.6 $ 256.6

Investments in Unconsolidated32

Investments in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments And Joint Ventures [Abstract]
Activity Related to Partnership's Investment in Unconsolidated Affiliate	The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Cayenne Total Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ — $ 240.8 Equity earnings (loss) 8.4 (3.7 ) (7.9 ) (13.4 ) — (16.6 ) Cash distributions (1) (10.6 ) — — — — (10.6 ) Acquisition — — — — 5.0 5.0 Contributions (2) — 0.4 1.2 0.1 1.8 3.5 Balance at September 30, 2017 $ 43.9 $ 55.3 $ 111.9 $ 4.2 $ 6.8 $ 222.1 (1) Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2017. 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)

Accounts Payable and Accrued 33

Accounts Payable and Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2017
Payables And Accruals [Abstract]
Schedule of Accounts Payable and Accrued Liabilities	September 30, 2017 December 31, 2016 Commodities $ 600.9 $ 574.5 Other goods and services 220.5 113.4 Interest 48.7 52.2 Permian Acquisition contingent consideration, estimated current portion 5.9 — Income and other taxes 57.3 19.1 Other 15.9 14.7 $ 949.2 $ 773.9

Debt Obligations (Tables)

Debt Obligations (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Schedule of Outstanding Debt	September 30, 2017 December 31, 2016 Current: Accounts receivable securitization facility, due December 2017 $ 278.1 $ 275.0 Senior unsecured notes, 5% fixed rate, due January 2018 (1) 250.5 — 528.6 275.0 Debt issuance costs, net of amortization (0.2 ) — Current debt obligations 528.4 275.0 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (2) 430.0 150.0 Senior unsecured notes: 5% fixed rate, due January 2018 (1) — 250.5 4⅛% fixed rate, due November 2019 749.4 749.4 6⅜% fixed rate, due August 2022 — 278.7 5¼% fixed rate, due May 2023 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 (3) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 48.1 Unamortized premium 0.4 0.5 3,958.0 4,207.3 Debt issuance costs, net of amortization (24.4 ) (30.3 ) Long-term debt 3,933.6 4,177.0 Total debt obligations $ 4,462.0 $ 4,452.0 Irrevocable standby letters of credit outstanding $ 22.4 $ 13.2 (1) The 5% Notes (“5% Senior Notes due 2018”) were reclassified to a current liability in January 2017. Prior to that date, the notes were classified as a long-term liability on our Consolidated Balance Sheets. These notes were redeemed on October 30, 2017. (2) As of September 30, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,147.6 million. (3) Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.
Interest Rates Incurred on Variable-Rate Debt Obligations	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2017: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.0% - 5.3% 3.2% Accounts receivable securitization facility 1.8% - 2.2% 2.0%

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	9 Months Ended
	Sep. 30, 2017
Other Liabilities Noncurrent [Abstract]
Other Long-term Liabilities	Other long-term liabilities are comprised of the following obligations: September 30, 2017 December 31, 2016 Asset retirement obligations $ 49.4 $ 64.1 Mandatorily redeemable preferred interests 80.0 68.5 Deferred revenue 67.5 69.8 Permian Acquisition contingent consideration, noncurrent portion 284.9 — Other liabilities 3.1 2.9 Total long-term liabilities $ 484.9 $ 205.3
Changes in Aggregate Asset Retirement Obligations	The changes in our ARO are as follows Balance at December 31, 2016 $ 64.1 Additions (1) 0.8 Reduction due to sale of VGS (21.6 ) Change in cash flow estimate 3.1 Accretion expense 3.0 Balance at September 30, 2017 $ 49.4 _____________________________________________________________________________________________________________________________________________________________ (1) Amount reflects ARO 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 3.0 Change in estimated redemption value included in interest expense 8.5 Balance at September 30, 2017 $ 80.0
Components of Deferred Revenue	The following table shows the components of deferred revenue: September 30, 2017 December 31, 2016 Splitter agreement $ 43.0 $ 43.0 Gas contract amendment 18.6 19.7 Other deferred revenue 5.9 7.1 Total deferred revenue $ 67.5 $ 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 (2.3 ) Balance at September 30, 2017 $ 67.5
Schedule of Changes in Contingent Consideration	The following table shows the changes in contingent consideration: Balance at March 1, 2017 (acquisition date) $ 461.6 Measurement period adjustment of acquisition date value (45.3 ) Decrease in fair value due to factors occurring after acquisition date (125.5 ) Balance at September 30, 2017 290.8 Less: Current portion (5.9 ) Long-term balance at September 30, 2017 $ 284.9

Partnership Units and Related36

Partnership Units and Related Matters (Tables)	9 Months Ended
	Sep. 30, 2017
Partners Capital [Abstract]
Schedule of Distributions	The following details the distributions declared or paid by us for the nine months ended September 30, 2017: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. September 30, 2017 November 10, 2017 $ 225.4 $ 222.6 June 30, 2017 August 10, 2017 225.4 222.6 March 31, 2017 May 11, 2017 209.6 206.8 December 31, 2016 February 10, 2017 198.1 195.3

Derivative Instruments and He37

Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Notional Volume of Commodity Hedges	At September 30, 2017, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 2020 Natural Gas Swaps MMBtu/d 160,347 151,100 116,136 - Natural Gas Basis Swaps MMBtu/d 92,200 15,726 12,500 10,445 Natural Gas Futures MMBtu/d - 1,103 - - Natural Gas Options MMBtu/d 22,900 9,486 - - NGL Swaps Bbl/d 23,432 12,858 7,399 - NGL Futures Bbl/d 38,880 6,589 329 - NGL Options Bbl/d 3,094 2,986 410 - Condensate Swaps Bbl/d 3,150 2,420 1,293 - 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 on 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 September 30, 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 $ 18.4 $ 79.9 $ 16.7 $ 48.6 Long-term 13.7 14.4 5.1 26.1 Total derivatives designated as hedging instruments $ 32.1 $ 94.3 $ 21.8 $ 74.7 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.3 $ 1.0 $ 0.1 $ 0.5 Long-term - 0.5 - - Total derivatives not designated as hedging instruments $ 0.3 $ 1.5 $ 0.1 $ 0.5 Total current position $ 18.7 $ 80.9 $ 16.8 $ 49.1 Total long-term position 13.7 14.9 5.1 26.1 Total derivatives $ 32.4 $ 95.8 $ 21.9 $ 75.2
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet	The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation September 30, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 18.7 $ (79.5 ) $ 44.6 $ 3.6 $ (19.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (1.4 ) - - (1.4 ) 18.7 (80.9 ) 44.6 3.6 (21.2 ) Long Term Position Counterparties with offsetting positions or collateral 13.5 (14.2 ) - 6.5 (7.2 ) Counterparties without offsetting positions - assets 0.2 - - 0.2 - Counterparties without offsetting positions - liabilities - (0.7 ) - - (0.7 ) 13.7 (14.9 ) - 6.7 (7.9 ) Total Derivatives Counterparties with offsetting positions or collateral 32.2 (93.7 ) 44.6 10.1 (27.0 ) Counterparties without offsetting positions - assets 0.2 - - 0.2 - Counterparties without offsetting positions - liabilities - (2.1 ) - - (2.1 ) $ 32.4 $ (95.8 ) $ 44.6 $ 10.3 $ (29.1 ) 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 September 30, Nine Months Ended September 30, Hedging Relationships 2017 2016 2017 2016 Commodity contracts $ (106.8 ) $ 12.9 $ (10.5 ) $ (40.5 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended September 30, Nine Months Ended September 30, Location of Gain (Loss) 2017 2016 2017 2016 Revenues $ (2.1 ) $ 8.1 $ (2.2 ) $ 50.6
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 September 30, Nine Months Ended September 30, as Hedging Instruments Derivatives 2017 2016 2017 2016 Commodity contracts Revenue $ (1.5 ) $ (0.3 ) $ (2.9 ) $ 1.3

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Breakdown by Fair Value Hierarchy Category for Financial Instruments Included on Consolidated Balance Sheets	The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: September 30, 2017 Fair Value Carrying 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) $ 32.0 $ 32.0 $ — $ 29.0 $ 3.0 Liabilities from commodity derivative contracts (1) 95.4 95.4 — 86.5 8.9 Permian Acquisition contingent consideration (2) 290.8 290.8 — — 290.8 TPL contingent consideration (3) 2.5 2.5 — — 2.5 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 103.9 103.9 — — — TRP Revolver 430.0 430.0 — 430.0 — Senior unsecured notes 3,778.5 3,881.2 — 3,881.2 — Accounts receivable securitization facility 278.1 278.1 — 278.1 — December 31, 2016 Fair Value Carrying 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 Permian Acquisition contingent consideration (2) — — — — — 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 68.0 68.0 — — — TRP Revolver 150.0 150.0 — 150.0 — Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — 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 13 – 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, which is carried at fair value. See Note 4 – Acquisitions and Divestitures. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is 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) - (290.8 ) New Level 3 derivative instruments (0.8 ) - Transfers out of Level 3 (2) 1.6 - Settlements included in Revenue 0.4 - Unrealized gain/(loss) included in OCI (3.5 ) - Balance, September 30, 2017 $ (5.9 ) $ (293.3 ) (1) Represents the September 30, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 –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.

Related Party Transactions - 39

Related Party Transactions - Targa (Tables)	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Summary of Transactions with Affiliates	The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Targa billings of payroll and related costs included in operating expense $ 54.0 $ 42.6 $ 148.6 $ 125.0 Targa allocation of general and administrative expense 43.2 40.1 126.6 117.7 Cash distributions to Targa based on IDR, general partner and limited partner ownership (1) 222.6 178.9 624.7 395.1 Cash contributions from Targa related to limited partner ownership (2) 14.7 210.7 1,587.5 1,167.2 Cash contributions from Targa to maintain its 2% general partner ownership 0.3 4.3 32.5 23.8 _______________________ (1) As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on general partner and limited partner ownership. (2) The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 12 – Partnership Units and Related Matters.

Other Operating (Income) Expe40

Other Operating (Income) Expense (Tables)	9 Months Ended
	Sep. 30, 2017
Other Income And Expenses [Abstract]
Other Operating (Income) Expense	Other operating (income) expense is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Loss on sale or disposal of assets (1) $ 0.3 $ 4.7 $ 16.6 $ 5.7 Miscellaneous business tax 0.3 0.2 0.6 0.4 $ 0.6 $ 4.9 $ 17.2 $ 6.1 __________________________________________________________________________________________________ (1) Comprised primarily of a $16.1 million loss in the first quarter of 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 Inform41

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Nine Months Ended September 30, 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 154.5 $ 197.1 Income taxes paid, net of refunds (4.9 ) 1.2 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 118.3 (0.5 ) Transfers from materials and supplies inventory to property, plant and equipment 2.8 1.9 Contribution of property, plant and equipment to investments in unconsolidated affiliates 1.0 — Change in ARO liability and property, plant and equipment due to revised cash flow estimate 3.1 (9.2 ) Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ 416.3 $ — Non-cash financing activities: Cancellation of treasury units $ — $ (10.4 ) Accrued distributions on unvested equity awards under share compensation arrangements — 0.2 _____________ (1) Interest capitalized on major projects was $8.3 million and $7.2 million for the nine months ended September 30, 2017 and 2016.

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Information by Segment	Reportable segment information is shown in the following tables: Three Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 200.3 $ 1,672.2 $ (1.0 ) $ — $ 1,871.5 Fees from midstream services 148.5 111.8 — — 260.3 348.8 1,784.0 (1.0 ) — 2,131.8 Intersegment revenues Sales of commodities 783.7 80.6 — (864.3 ) — Fees from midstream services 1.7 7.0 — (8.7 ) — 785.4 87.6 — (873.0 ) — Revenues $ 1,134.2 $ 1,871.6 $ (1.0 ) $ (873.0 ) $ 2,131.8 Operating margin $ 198.3 $ 115.9 $ (1.0 ) $ — * Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 295.9 $ 71.0 $ — $ 11.8 $ 378.7 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Three Months Ended September 30, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 172.2 $ 1,215.3 $ 11.2 $ — $ 1,398.7 Fees from midstream services 120.6 133.0 — — 253.6 292.8 1,348.3 11.2 — 1,652.3 Intersegment revenues Sales of commodities 574.8 76.3 — (651.1 ) — Fees from midstream services 1.9 6.6 — (8.5 ) — 576.7 82.9 — (659.6 ) — Revenues $ 869.5 $ 1,431.2 $ 11.2 $ (659.6 ) $ 1,652.3 Operating margin $ 149.4 $ 126.0 $ 11.2 $ — * Other financial information: Total assets (1) $ 10,047.3 $ 2,737.5 $ 47.2 $ 76.2 $ 12,908.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 97.1 $ 36.2 $ — $ 1.3 $ 134.6 ____________________________________________________________________________________________ (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Nine Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 544.4 $ 4,804.8 $ 3.9 $ — $ 5,353.1 Fees from midstream services 399.3 359.7 — — 759.0 943.7 5,164.5 3.9 — 6,112.1 Intersegment revenues Sales of commodities 2,209.2 237.8 — (2,447.0 ) — Fees from midstream services 5.1 21.1 — (26.2 ) — 2,214.3 258.9 — (2,473.2 ) — Revenues $ 3,158.0 $ 5,423.4 $ 3.9 $ (2,473.2 ) $ 6,112.1 Operating margin $ 549.3 $ 358.5 $ 3.9 $ — * Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 730.7 $ 241.8 $ — $ 15.2 $ 987.7 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 _____________________________________________________________________________________________ (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure. Nine Months Ended September 30, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 441.3 $ 3,384.7 $ 56.9 $ — $ 3,882.9 Fees from midstream services 360.9 434.6 — — 795.5 802.2 3,819.3 56.9 — 4,678.4 Intersegment revenues Sales of commodities 1,455.8 176.3 — (1,632.1 ) — Fees from midstream services 5.8 15.1 — (20.9 ) — 1,461.6 191.4 — (1,653.0 ) — Revenues $ 2,263.8 $ 4,010.7 $ 56.9 $ (1,653.0 ) $ 4,678.4 Operating margin $ 404.1 $ 424.6 $ 56.9 $ — * Other financial information: Total assets (1) $ 10,047.3 $ 2,737.5 $ 47.2 $ 76.2 $ 12,908.2 Goodwill $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 271.3 $ 151.9 $ — $ 3.3 $ 426.5 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. * Total operating margin is not presented in this table as it represents a non-GAAP measure.
Revenues by Product and Service	The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Sales of commodities: Natural gas $ 504.1 $ 465.6 $ 1,480.9 $ 1,102.0 NGL 1,274.9 866.7 3,623.9 2,575.8 Condensate 44.9 35.0 135.9 96.2 Petroleum products 48.6 20.2 108.5 52.0 Derivative activities (1.0 ) 11.2 3.9 56.9 1,871.5 1,398.7 5,353.1 3,882.9 Fees from midstream services: Fractionating and treating 29.8 33.2 92.8 94.8 Storage, terminaling, transportation and export 75.0 89.7 247.8 316.3 Gathering and processing 138.0 110.9 368.5 329.9 Other 17.5 19.8 49.9 54.5 260.3 253.6 759.0 795.5 Total revenues $ 2,131.8 $ 1,652.3 $ 6,112.1 $ 4,678.4
Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes	The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 198.3 $ 149.4 $ 549.3 $ 404.1 Logistics and Marketing operating margin 115.9 126.0 358.5 424.6 Other operating margin (1.0 ) 11.2 3.9 56.9 Depreciation and amortization expenses (208.3 ) (184.0 ) (602.8 ) (563.6 ) General and administrative expenses (46.6 ) (44.0 ) (139.4 ) (132.3 ) Impairment of property, plant and equipment (378.0 ) — (378.0 ) — Impairment of goodwill — — — (24.0 ) Interest expense, net (51.9 ) (57.9 ) (169.5 ) (171.2 ) Other, net 126.6 (5.8 ) 78.4 5.0 Income (loss) before income taxes $ (245.0 ) $ (5.1 ) $ (299.6 ) $ (0.5 )

Organization and Operations (De

Organization and Operations (Details)	Feb. 17, 2016$ / shares	Sep. 30, 2017shares	Dec. 31, 2016shares
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items]
Conversion ratio in stock-for-unit transaction	0.62
Common stock, par value (in dollars per share) | $ / shares	$ 0.001
Series A Cumulative Redeemable Perpetual Preferred Units [Member]
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items]
Preferred units, outstanding | shares		5,000,000	5,000,000
Preferred units dividend percentage		9.00%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details)	May 30, 2017USD ($)	May 09, 2017USD ($)amiMMcf	Mar. 01, 2017USD ($)aMMcfMBbls	Jan. 26, 2017USD ($)$ / sharesshares	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017MMcf
Business Acquisition [Line Items]
Shares of common stock issued (including shares sold pursuant to underwriters’ overallotment option) | shares				9,200,000
Shares issued price | $ / shares				$ 57.65
Net proceeds from public offering				$ 524,200,000
Permian Acquisition [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition			$ 484,100,000
Additional cash payments related to purchase consideration	$ 90,000,000
Additional cash that may be paid based on potential earn-out payment			461,600,000		$ 290,800,000	$ 290,800,000
Revenues from acquired businesses					75,200,000
Net loss from acquired businesses					$ (21,500,000)
Acquisition-related expenses						$ 5,600,000
Allocation of property, plant and equipment			255,800,000
Allocation of intangible assets for customer contracts			692,300,000
Permian Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment			$ 935,000,000
Permian Acquisition [Member] | Targa Resources Corp. [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
New Delaware [Member]
Business Acquisition [Line Items]
Average weighted contract life			14 years
Gas processing capacity | MMcf			70
Crude gathering capacity | MBbls			40
New Delaware [Member] | Scenario Forecast [Member]
Business Acquisition [Line Items]
Gas processing capacity | MMcf							60
New Delaware [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering assets | a			145,000
New Midland [Member]
Business Acquisition [Line Items]
Average weighted contract life			13 years
Gas processing capacity | MMcf			10
Crude gathering capacity | MBbls			40
New Midland [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering assets | a			105,000
Flag City Acquisition [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition		$ 60,000,000
Area of gas gathering and processing and crude gathering assets | a		102.1
Gas processing capacity | MMcf		150
Additional final adjustment due on base purchase price paid		$ 3,600,000
Number of miles of gas gathering pipeline systems | mi		24
Allocation of property, plant and equipment		$ 52,300,000
Allocation of intangible assets for customer contracts		7,700,000
Allocation of current assets and liabilities, net		3,600,000
Flag City Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Acquisition-related expenses		$ 100,000

Acquisitions and Divestitures45

Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pro forma consolidated results of operations [Abstract]
Revenues	$ 2,131.8	$ 1,663	$ 6,126.2	$ 4,697.3
Net income (loss)	$ (244.7)	$ (18.3)	(297)	$ (44.7)
Acquisition-related costs			$ 5.6

Acquisitions and Divestitures46

Acquisitions and Divestitures - Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions	Mar. 01, 2017	Sep. 30, 2017	Sep. 30, 2016
Fair Value of Consideration Transferred by Targa [Abstract]
Cash paid, net of $3.3 million cash acquired		$ 570.8	$ 0
Permian Acquisition [Member]
Fair Value of Consideration Transferred by Targa [Abstract]
Total fair value of consideration transferred	$ 987.1
Targa Resources Corp [Member] | Permian Acquisition [Member]
Fair Value of Consideration Transferred by Targa [Abstract]
Cash paid, net of $3.3 million cash acquired	570.8
Contingent consideration valuation as of the acquisition date	416.3
Total fair value of consideration transferred	$ 987.1

Business Acquisitions, Fair Val

Business Acquisitions, Fair Value of Consideration Transferred (Parenthetical) (Details) $ in Millions	Mar. 01, 2017USD ($)
Targa Resources Corp [Member] | Permian Acquisition [Member]
Fair Value of Consideration Transferred by Targa [Abstract]
Cash acquired from acquisition	$ 3.3

Acquisitions and Divestitures48

Acquisitions and Divestitures - Fair Value of the Assets and Liabilities Assumed at Acquisition Date (Details) - USD ($) $ in Millions	Sep. 30, 2017	Mar. 01, 2017	Dec. 31, 2016
Fair value determination (final) [Abstract]
Goodwill	$ 256.6	$ 46.6	$ 210
Permian Acquisition [Member]
Fair value determination (final) [Abstract]
Trade and other current receivables, net		6.7
Other current assets		0.6
Property, plant and equipment		255.8
Intangible assets		692.3
Current liabilities		(14.1)
Other long-term liabilities		(0.8)
Total identifiable net assets		940.5
Goodwill		46.6
Total fair value of assets acquired and liabilities assumed		$ 987.1

Acquisitions and Divestitures49

Acquisitions and Divestitures - Additional Information Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($)	3 Months Ended			7 Months Ended	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Mar. 01, 2017	Dec. 31, 2016
Fair value determination (final) [Abstract]
Goodwill	$ 256,600,000			$ 256,600,000	$ 256,600,000		$ 46,600,000	$ 210,000,000
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Trade receivables, preliminary fair value							6,700,000
Increase (decrease) in fair value of contingent consideration liability	(126,800,000)		$ (300,000)		(125,600,000)	$ (300,000)
Depreciation and amortization expense	208,300,000		$ 184,000,000		602,800,000	$ 563,600,000
Permian Acquisition [Member]
Fair value determination (final) [Abstract]
Goodwill							$ 46,600,000
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Increase (decrease) in fair value of contingent consideration liability	(126,600,000)	$ (45,300,000)		(125,500,000)	$ (125,500,000)
Measurement period adjustment	$ 0			$ (45,300,000)
Measurement Period Adjustments [Member]
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Increase (decrease) in fair value of contingent consideration liability		(45,300,000)
Intangible assets		66,700,000
Other assets, net		400,000
Goodwill		112,400,000
Depreciation and amortization expense		$ 400,000

Acquisitions and Divestitures50

Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - USD ($)	3 Months Ended			7 Months Ended	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Mar. 01, 2017
Business Acquisition [Line Items]
Other income related to change in fair value of contingent consideration	$ 126,800,000		$ 300,000		$ 125,600,000	$ 300,000
Permian Acquisition [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment	290,800,000			$ 290,800,000	290,800,000		$ 461,600,000
Potential earn-out payments acquisition date fair value	416,300,000	$ 416,300,000		416,300,000	416,300,000
Other income related to change in fair value of contingent consideration	126,600,000	$ 45,300,000		125,500,000	125,500,000
First potential earn-out payments acquisition date fair value	5,900,000			5,900,000	5,900,000
Permian Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment							935,000,000
Permian Acquisition [Member] | Other Long-term Liabilities [Member]
Business Acquisition [Line Items]
Potential earn-out payments acquisition date fair value	461,600,000			461,600,000	461,600,000		$ 416,300,000
Second potential earn-out payments acquisition date fair value	284,900,000			284,900,000	284,900,000
Permian Acquisition [Member] | Accounts Payable and Accrued Liabilities [Member]
Business Acquisition [Line Items]
First potential earn-out payments acquisition date fair value	$ 5,900,000			$ 5,900,000	$ 5,900,000

Acquisitions and Divestitures51

Acquisitions and Divestitures - Additional Information Purchase of Outstanding Silver Oak II Interests (Details)	Jun. 01, 2017USD ($)
SN Catarina, LLC [Member]
Business Acquisition [Line Items]
Business acquisition remaining interests acquired	10.00%
Purchase price of business acquisition	$ 12,500,000
Silver Oak II [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Business	$ 0

Acquisitions and Divestitures52

Acquisitions and Divestitures - Additional Information 2017 Divestiture (Details) - USD ($) $ in Millions	Apr. 04, 2017	Mar. 31, 2017	Sep. 30, 2017
Venice Gathering System, L.L.C. [Member]
Business Acquisition [Line Items]
Gain (loss) from sale of divestiture of businesses		$ (16.1)
Venice Gathering System, L.L.C. [Member] | Disposal Group, Not Discontinued Operations [Member]
Business Acquisition [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 Acquisition [Line Items]
Ownership interest			76.80%

Acquisitions and Divestitures53

Acquisitions and Divestitures - Additional Information 2017 Joint Venture (Details) - Grand Prix Joint Venture [Member] $ in Millions	1 Months Ended	4 Months Ended
	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	May 31, 2017MBbls
Business Acquisition [Line Items]
Expected net growth capital expenditures | $	$ 975
Blackstone Energy Partners [Member]
Business Acquisition [Line Items]
Percentage of joint venture interest sold	25.00%
Scenario Forecast [Member]
Business Acquisition [Line Items]
Expected net growth capital expenditures | $		$ 275
Permian Basin [Member]
Business Acquisition [Line Items]
Capacity of pipeline | MBbls			300
Maximum [Member] | Permian Basin [Member]
Business Acquisition [Line Items]
Capacity of pipeline | MBbls			550

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Commodities	$ 255.6	$ 126.9
Materials and supplies	11.8	10.8
Total inventory	$ 267.4	$ 137.7

Property, Plant and Equipment55

Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 13,685.2		$ 13,685.2		$ 12,511.9
Accumulated depreciation	(3,616.4)		(3,616.4)		(2,821)
Property, plant and equipment, net	10,068.8		10,068.8		9,690.9
Intangible assets	2,736.6		2,736.6		2,036.6
Accumulated amortization	(521.8)		(521.8)		(382.6)
Intangible assets, net	2,214.8		2,214.8		1,654
Non-cash pre-tax impairment charges	378	$ 0	378	$ 0
Additions from acquisition			$ 692.3
Estimated useful life			20 years
Permian Acquisition [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			15 years
Flag City Acquisition [Member]
Property Plant And Equipment [Line Items]
Additions from acquisition			$ 7.7
Estimated useful life			10 years
Badlands [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			20 years
Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			10 years
Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			20 years
Gathering Systems [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	6,900.8		$ 6,900.8		6,626.9
Gathering Systems [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			5 years
Gathering Systems [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			20 years
Processing and Fractionation Facilities [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	3,571.3		$ 3,571.3		3,383.6
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			25 years
Terminaling and Storage Facilities [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	1,238		$ 1,238		1,205
Terminaling and Storage Facilities [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			5 years
Terminaling and Storage Facilities [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			25 years
Transportation Assets [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	343.2		$ 343.2		451.4
Transportation Assets [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			10 years
Transportation Assets [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			25 years
Other Property, Plant and Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	284.7		$ 284.7		274
Other Property, Plant and Equipment [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			3 years
Other Property, Plant and Equipment [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life			25 years
Land [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	123.8		$ 123.8		121.2
Construction in Progress [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 1,223.4		$ 1,223.4		$ 449.8

Property, Plant and Equipment56

Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) $ in Millions	Sep. 30, 2017USD ($)
Estimated amortization expense for intangible assets [Abstract]
2,017	$ 188.4
2,018	182.6
2,019	171.6
2,020	159.4
2,021	$ 149.5

Property, Plant and Equipment57

Property, Plant and Equipment and Intangible Assets, Schedule of Changes in Intangible Assets(Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Intangible Assets, net [Roll Forward]
Balance at December 31, 2016	$ 1,654
Additions from Acquisition	692.3
Amortization	(139.2)
Balance at September 30, 2017	2,214.8
Flag City Acquisition [Member]
Intangible Assets, net [Roll Forward]
Additions from Acquisition	$ 7.7

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill impairment	$ 0	$ 0	$ 24	$ 0	$ 24

Goodwill - Changes in Net Book

Goodwill - Changes in Net Book Value of Goodwill (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Goodwill [Roll Forward]
Beginning balance	$ 210
Permian Acquisition, March 1, 2017	46.6
Ending balance	256.6
WestTX [Member]
Goodwill [Roll Forward]
Beginning balance	174.7
Ending balance	174.7
SouthTX [Member]
Goodwill [Roll Forward]
Beginning balance	35.3
Ending balance	35.3
Permian [Member]
Goodwill [Roll Forward]
Permian Acquisition, March 1, 2017	46.6
Ending balance	$ 46.6

Investments in Unconsolidated60

Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended
	Jul. 31, 2017USD ($)	Mar. 31, 2017USD ($)	Sep. 30, 2017USD ($)JointVenture	Oct. 31, 2017
Schedule Of Equity Method Investments [Line Items]
Payment made to acquire			$ 5
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			38.80%
Payment made to acquire			$ 0
T2 Joint Ventures [Member]
Schedule Of Equity Method Investments [Line Items]
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture			3
T2 La Salle [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			75.00%
Payment made to acquire			$ 0
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			50.00%
Payment made to acquire			$ 0
T2 EF Cogen [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			50.00%
Payment made to acquire			$ 0
Impairment loss		$ 12
Cayenne Joint Venture [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	50.00%		50.00%
Payment made to acquire	$ 5		$ 5
Expected period for completion of project			2017-11
T2 LaSalle and T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Unamortized excess fair value			$ 26.8
Preliminary estimated useful lives of the underlying assets			20 years
GCX Project [Member] | Subsequent Event [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest				25.00%

Investments in Unconsolidated61

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Jul. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					$ 240.8
Equity earnings (loss)			$ 0.2	$ (2.2)	(16.6)	$ (11.4)
Cash distributions	[1]				(10.6)
Acquisition					5
Contributions	[2]				3.5
Balance at end of period			222.1		222.1
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					46.1
Equity earnings (loss)					8.4
Cash distributions	[1]				(10.6)
Acquisition					0
Contributions	[2]				0
Balance at end of period			43.9		43.9
T2 La Salle [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					58.6
Equity earnings (loss)					(3.7)
Cash distributions	[1]				0
Acquisition					0
Contributions	[2]				0.4
Balance at end of period			55.3		55.3
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					118.6
Equity earnings (loss)					(7.9)
Cash distributions	[1]				0
Acquisition					0
Contributions	[2]				1.2
Balance at end of period			111.9		111.9
T2 EF Cogen [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					17.5
Equity earnings (loss)					(13.4)
Cash distributions	[1]				0
Acquisition					0
Contributions	[2]				0.1
Balance at end of period			4.2		4.2
Cayenne Joint Venture [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period					0
Equity earnings (loss)					0
Cash distributions	[1]				0
Acquisition		$ 5			5
Contributions	[2]				1.8
Balance at end of period			$ 6.8		$ 6.8
[1]	Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2017. 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 Unconsolidated62

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Schedule Of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate	$ 2.2	$ 3.4
Contribution of property, plant and equipment to investment in unconsolidated affiliates	1
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate	2.2
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Contribution of property, plant and equipment to investment in unconsolidated affiliates	$ 1

Accounts Payable and Accrued 63

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$ 600.9	$ 574.5
Other goods and services	220.5	113.4
Interest	48.7	52.2
Income and other taxes	57.3	19.1
Other	15.9	14.7
Accounts payable and accrued liabilities	949.2	$ 773.9
Permian Acquisition [Member]
Components of accounts payable and accrued liabilities [Abstract]
Permian Acquisition contingent consideration, estimated current portion	$ 5.9

Accounts Payable and Accrued 64

Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Outstanding checks	$ 29.2	$ 30.2

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Current:
Current debt		$ 528.6	$ 275
Debt issuance costs, net of amortization		(0.2)
Current debt obligations		528.4	275
Long-term [Abstract]
Long-term debt		3,933.6	4,177
Long-term debt including unamortized premium (discount)		3,958	4,207.3
Total debt obligations		4,462	4,452
Debt issuance costs, net of amortization		(24.4)	(30.3)
Irrevocable standby letters of credit outstanding		22.4	13.2
Senior Unsecured 5% Notes due January 2018 [Member]
Current:
Current unsecured debt	[1]	250.5
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Long-term [Abstract]
Long-term debt	[1]		250.5
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member]
Long-term [Abstract]
Long-term debt		749.4	749.4
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Long-term [Abstract]
Long-term debt			278.7
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]
Long-term [Abstract]
Long-term debt		559.6	559.6
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]
Long-term [Abstract]
Long-term debt		583.9	583.9
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Long-term [Abstract]
Long-term debt		580.1	580.1
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member]
Long-term [Abstract]
Long-term debt		500	500
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member]
Long-term [Abstract]
Long-term debt		500	500
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		0.4	0.5
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[3]	430	150
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2017 [Member]
Current:
Accounts receivable securitization facility, due December 2017		$ 278.1	$ 275
[1]	The 5% Notes (“5% Senior Notes due 2018”) were reclassified to a current liability in January 2017. Prior to that date, the notes were classified as a long-term liability on our Consolidated Balance Sheets. These notes were redeemed on October 30, 2017.
[2]	Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.
[3]	As of September 30, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,147.6 million.

Debt Obligations (Parenthetical

Debt Obligations (Parenthetical) (Details) - USD ($)		9 Months Ended
		Sep. 30, 2017	Jun. 30, 2017	Feb. 23, 2017	Dec. 31, 2016
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Debt Instrument [Line Items]
Maturity date	[1]	Oct. 31, 2020
Maximum borrowing capacity		$ 1,600,000,000
Remaining borrowing capacity		$ 1,147,600,000
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt		5.00%
Debt instrument redemption date		Oct. 30, 2017
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 350,000,000	$ 275,000,000
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2017 [Member]
Debt Instrument [Line Items]
Maturity date		Dec. 31, 2017
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Maturity date	[2]	Jan. 31, 2018
Interest rate on fixed rate debt	[2]	5.00%
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member]
Debt Instrument [Line Items]
Maturity date		Nov. 30, 2019
Interest rate on fixed rate debt		4.125%
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Debt Instrument [Line Items]
Maturity date		Aug. 31, 2022
Interest rate on fixed rate debt		6.375%	6.375%
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]
Debt Instrument [Line Items]
Maturity date		May 31, 2023
Interest rate on fixed rate debt		5.25%
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]
Debt Instrument [Line Items]
Maturity date		Nov. 30, 2023
Interest rate on fixed rate debt		4.25%
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Debt Instrument [Line Items]
Maturity date		Mar. 31, 2024
Interest rate on fixed rate debt		6.75%
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%
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%
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	[3]	Nov. 30, 2021
Interest rate on fixed rate debt	[3]	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	[3]	Aug. 31, 2023
Interest rate on fixed rate debt	[3]	5.875%
[1]	As of September 30, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,147.6 million.
[2]	The 5% Notes (“5% Senior Notes due 2018”) were reclassified to a current liability in January 2017. Prior to that date, the notes were classified as a long-term liability on our Consolidated Balance Sheets.
[3]	Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

Debt Obligations, Interest Rate

Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details)	Sep. 30, 2017
Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred	2.00%
Minimum [Member] | Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	1.80%
Maximum [Member] | Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	2.20%
TRP Revolver [Member]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred	3.20%
TRP Revolver [Member] | Minimum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	3.00%
TRP Revolver [Member] | Maximum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	5.30%

Debt Obligations - Additional I

Debt Obligations - Additional Information (Details) - USD ($)		1 Months Ended	3 Months Ended
		Oct. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Feb. 23, 2017	Dec. 31, 2016
Senior Unsecured 5% Notes due January 2018 [Member] | Scenario Forecast [Member]
Debt Instrument [Line Items]
Write off debt issuance cost			$ 200,000
Senior Unsecured 5% Notes due January 2018 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt		5.00%
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Senior notes issued		$ 750,000,000
Interest rate on fixed rate debt		5.00%
Net proceeds from private placement of notes		$ 744,400,000
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt	[1]			5.00%
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity					$ 350,000,000	$ 275,000,000
Outstanding securitization facility				$ 278,100,000
[1]	The 5% Notes (“5% Senior Notes due 2018”) were reclassified to a current liability in January 2017. Prior to that date, the notes were classified as a long-term liability on our Consolidated Balance Sheets.

Debt Obligations, Debt Repurcha

Debt Obligations, Debt Repurchases & Extinguishments - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Debt Instrument [Line Items]
Gain (loss) from financing activities		$ 0	$ 0	$ (10.7)	$ 21.4
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt	6.375%	6.375%		6.375%
Maturity date				Aug. 31, 2022
Face amount of notes redeemed	$ 278.7
Redemption price, percentage of face value	103.188%
Gain (loss) from financing activities	$ (10.7)
Premiums paid	8.9
Write off debt issuance cost	$ 1.8

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Other Liabilities Noncurrent [Line Items]
Asset retirement obligations	$ 49.4	$ 64.1
Mandatorily redeemable preferred interests	80	68.5
Deferred revenue	67.5	69.8
Other liabilities	3.1	2.9
Total long-term liabilities	484.9	$ 205.3
Permian Acquisition [Member]
Other Liabilities Noncurrent [Line Items]
Permian Acquisition contingent consideration, noncurrent portion	$ 284.9

Other Long-term Liabilities - C

Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2016		$ 64.1
Additions	[1]	0.8
Reduction due to sale of VGS		(21.6)
Change in cash flow estimate		3.1	$ (9.2)
Accretion expense		3	$ 3.5
Balance at September 30, 2017		$ 49.4
[1]	Amount reflects ARO assumed from the Permian Acquisition.

Other Long-term Liabilities, Ma

Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)JointVenture	Sep. 30, 2016USD ($)
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	(8.5)	$ 18.8
Balance at September 30, 2017	80
Mandatorily Redeemable Preferred 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	3
Change in estimated redemption value included in interest expense	8.5
Balance at September 30, 2017	$ 80
Mandatorily Redeemable Preferred Interests [Member] | Joint Ventures [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Number of joint ventures | JointVenture	2
Mandatorily Redeemable Preferred Interests [Member] | WestOK [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Ownership interest	100.00%
Mandatorily Redeemable Preferred Interests [Member] | WestTX [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Ownership interest	72.80%

Other Long-term Liabilities, De

Other Long-term Liabilities, Deferred Revenue (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)	Oct. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 27, 2015bbl
Deferred Revenue [Abstract]
Deferred Revenue	$ 67.5		$ 69.8
Channelview Splitter [Member]
Deferred Revenue [Abstract]
Storage capacity of Channelview Terminal | bbl				730,000
Channelview Splitter capability to split crude oil and condensate barrel per day | bbl				35,000
Channelview Splitter project expected completion period	2018-06
Channelview Splitter project estimated total cost	$ 140
Spilitter agreement annual deferred revenue payments receivable through 2022	$ 43
Deferred revenue recognition period over Splitter Agreement start-up period	2,018
Deferred revenue recognition period over Splitter Agreement end period	2,025
Deferred Revenue	$ 43		$ 43
Subsequent Event [Member] | Channelview Splitter [Member]
Deferred Revenue [Abstract]
Deferred Revenue		$ 43

Other Long-term Liabilities, Co

Other Long-term Liabilities, Components Of Deferred Revenue (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 67.5	$ 69.8
Other Deferred Revenue [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	5.9	7.1
Gas Contract Amendment [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	18.6	19.7
Channelview Splitter [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 43	$ 43

Other Long-term Liabilities, Ch

Other Long-term Liabilities, Changes In Deferred Revenue (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Other Liabilities Noncurrent [Abstract]
Balance at December 31, 2016	$ 69.8
Revenue recognized	(2.3)
Balance at September 30, 2017	$ 67.5

Other Long-term Liabilities, 76

Other Long-term Liabilities, Contingent Consideration (Details) - USD ($) $ in Millions	3 Months Ended			7 Months Ended	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Mar. 01, 2017
Business Acquisition Contingent Consideration [Line Items]
Increase (decrease) in fair value of contingent consideration liability	$ (126.8)		$ (0.3)		$ (125.6)	$ (0.3)
Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
Potential earn-out payments acquisition date fair value	416.3	$ 416.3		$ 416.3	416.3
Increase (decrease) in fair value of contingent consideration liability	(126.6)	$ (45.3)		(125.5)	(125.5)
Additional cash that may be paid based on potential earn-out payment	290.8			290.8	290.8		$ 461.6
Other Long-term Liabilities [Member] | Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
Potential earn-out payments acquisition date fair value	461.6			461.6	461.6		$ 416.3
Second potential earn-out payments acquisition date fair value	284.9			284.9	284.9
Accounts Payable and Accrued Liabilities [Member] | Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
First potential earn-out payments acquisition date fair value	$ 5.9			$ 5.9	$ 5.9

Other Long-term Liabilities -77

Other Long-term Liabilities - Schedule of Changes in Contingent Consideration (Details) - USD ($)	3 Months Ended			7 Months Ended	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016
Business Acquisition Contingent Consideration [Line Items]
Decrease in fair value due to factors occurring after acquisition date	$ (126,800,000)		$ (300,000)		$ (125,600,000)	$ (300,000)
Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
Balance at March 1, 2017 (acquisition date)				$ 461,600,000
Measurement period adjustment of acquisition date value	0			(45,300,000)
Decrease in fair value due to factors occurring after acquisition date	(126,600,000)	$ (45,300,000)		(125,500,000)	(125,500,000)
Balance at September 30, 2017	290,800,000			290,800,000	290,800,000
Less: Current portion	(5,900,000)			(5,900,000)	(5,900,000)
Long-term balance at September 30, 2017	$ 284,900,000			$ 284,900,000	$ 284,900,000

Partnership Units and Related78

Partnership Units and Related Matters, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended				9 Months Ended
	Oct. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule Of Equity Method Investments [Line Items]
Total Distributions						$ 633.1	$ 542.6
Subsequent Event [Member] | Preferred Unit [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date of declaration for cash distribution	2017-10
Cash distribution declared per unit (in dollars per share)	$ 0.1875
Cash distribution to be paid	Nov. 15, 2017
Distributions Declared [Member]
Schedule Of Equity Method Investments [Line Items]
Date Paid Or to Be Paid		Nov. 10, 2017	Aug. 10, 2017
Total Distributions		$ 225.4	$ 225.4
Distributions to Targa Resources Corp.		$ 222.6	$ 222.6
Distributions Paid [Member]
Schedule Of Equity Method Investments [Line Items]
Date Paid Or to Be Paid				May 11, 2017	Feb. 10, 2017
Total Distributions				$ 209.6	$ 198.1
Distributions to Targa Resources Corp.				$ 206.8	$ 195.3

Partnership Units and Related79

Partnership Units and Related Matters - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended		10 Months Ended
	Oct. 31, 2015	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017
Limited Partners Capital Account [Line Items]
Contributions from Targa Resources Corp.			$ 1,620	$ 1,191
Distribution to holders of preferred units		$ 2.8	$ 8.4
Series A Preferred Units [Member]
Limited Partners Capital Account [Line Items]
Series A preferred limited partners units issued (in units)	5,000,000
Preferred stock, par value (in dollar per share)	$ 25
Series A Preferred Units Due November12020
Limited Partners Capital Account [Line Items]
Preferred unit, redemption price (in dollars per share)		$ 25	$ 25		$ 25
Preferred units distribution percentage	9.00%
Series A Preferred Units Due November12020 | London Interbank Offered Rate (LIBOR)
Limited Partners Capital Account [Line Items]
Percentage of variable interest rate for distribution on preferred units upon maturity	7.71%
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%
TRC/TRP Merger | Targa Resources Corp [Member]
Limited Partners Capital Account [Line Items]
Contributions from Targa Resources Corp.			$ 1,620

Derivative Instruments and He80

Derivative Instruments and Hedging Activities - Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended		31 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Feb. 27, 2015
Derivative [Line Items]
Estimated fair value of derivative instruments, net liability	$ (63,400,000)		$ (63,400,000)		$ (63,400,000)
Amount expected to reclassify commodity hedge related deferred losses to earnings before income taxes	64,100,000		64,100,000		64,100,000
Amount of deferred losses to be reclassified into earnings before income taxes over next twelve months	63,000,000		63,000,000		63,000,000
Targa Pipeline Partners LP [Member]
Derivative [Line Items]
Fair value of derivative assets						$ 102,100,000
Fair value of derivative contracts received as component of derivative contract settlement	1,400,000	$ 5,800,000	6,300,000	$ 20,900,000	$ 100,900,000
Ineffectiveness losses			$ 100,000	$ 300,000
Targa Pipeline Partners LP [Member] | Maximum [Member]
Derivative [Line Items]
Ineffectiveness losses	$ 100,000	$ 100,000

Derivative Instruments and He81

Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details)	9 Months Ended
	Sep. 30, 2017MMBTUbbl
Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	10,445
Year 2017 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	3,150
Year 2017 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	160,347
Year 2017 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	23,432
Year 2017 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	92,200
Year 2017 [Member] | Future | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2017 [Member] | Future | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	38,880
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)	3,094
Year 2018 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	2,420
Year 2018 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	151,100
Year 2018 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	12,858
Year 2018 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	15,726
Year 2018 [Member] | Future | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	1,103
Year 2018 [Member] | Future | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	6,589
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)	2,986
Year 2019 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	1,293
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	116,136
Year 2019 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	7,399
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	12,500
Year 2019 [Member] | Future | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2019 [Member] | Future | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	329
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)	410

Derivative Instruments and He82

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets	$ 32.4	$ 21.9
Derivative liabilities	95.8	75.2
Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	18.7	16.8
Long-term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	13.7	5.1
Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	80.9	49.1
Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	14.9	26.1
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	32.1	21.8
Derivative liabilities	94.3	74.7
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	18.4	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	13.7	5.1
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	79.9	48.6
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	14.4	26.1
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0.3	0.1
Derivative liabilities	1.5	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	0
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0.5
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0.5	$ 0

Derivative Instruments and He83

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross asset	$ 32.4	$ 21.9
Pro forma net presentation, asset, total	10.3	5.7
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	32.2	21.9
Pro forma net presentation, asset	10.1	5.7
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.2
Pro forma net presentation, asset	0.2
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	18.7	16.8
Pro forma net presentation, asset, current	3.6	5.7
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	18.7	16.8
Pro forma net presentation, asset	3.6	5.7
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	13.7	5.1
Pro forma net presentation, asset, noncurrent	6.7
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	13.5	$ 5.1
Pro forma net presentation, asset	6.5
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	$ 0.2

Derivative Instruments and He84

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative Liability [Abstract]
Gross liability	$ (95.8)	$ (75.2)
Pro forma net presentation, liability, total	(29.1)	(52)
Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(93.7)	(64.8)
Pro forma net presentation, liability, total	(27)	(41.6)
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(2.1)	(10.4)
Pro forma net presentation, liability, total	(2.1)	(10.4)
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	(80.9)	(49.1)
Pro forma net presentation, liability, current	(21.2)	(31)
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(79.5)	(46.1)
Pro forma net presentation, liability, current	(19.8)	(28)
Current Position [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 Position [Member]
Derivative Liability [Abstract]
Gross liability	(14.9)	(26.1)
Pro forma net presentation, liability, noncurrent	(7.9)	(21)
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(14.2)	(18.7)
Pro forma net presentation, liability, noncurrent	(7.2)	(13.6)
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(0.7)	(7.4)
Pro forma net presentation, liability, noncurrent	$ (0.7)	$ (7.4)

Derivative Instruments and He85

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross collateral	$ 44.6	$ 7
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	44.6	7
Current Position [Member]
Derivative Asset [Abstract]
Gross collateral	44.6	7
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	$ 44.6	$ 7

Derivative Instruments and He86

Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from OCI into Income (Effective Portion)	$ (2.1)	$ 8.1	$ (2.2)	$ 50.6
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives	(1.5)	(0.3)	(2.9)	1.3
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ (106.8)	$ 12.9	$ (10.5)	$ (40.5)

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) $ in Millions	Sep. 30, 2017USD ($)Swap
Fair Value Disclosures [Abstract]
Derivatives financial instruments, fair value, net	$ (63.4)
Derivative fair value of net liability if commodity price increases by 10 percent	149.9
Derivative fair value of net asset if commodity price decreases by 10 percent	$ 22.2
Number of natural gas basis swaps categorized as Level 3 | Swap	31

Fair Value Measurements, Breakd

Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2017	Mar. 01, 2017	Dec. 31, 2016
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts		$ 10.3		$ 5.7
Liabilities from commodity derivative contracts		29.1		52
Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment		290.8	$ 461.6
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment		290.8	$ 461.6
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	32		21
Liabilities from commodity derivative contracts	[1]	95.4		74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		103.9		68
Accounts receivable securitization facility		278.1		275
Carrying Value [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Carrying Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		430		150
Carrying Value [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	2.5
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	2.5
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			2.6
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			2.6
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		3,778.5		4,057.3
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	32		21
Liabilities from commodity derivative contracts	[1]	95.4		74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		103.9		68
Accounts receivable securitization facility		278.1		275
Fair Value [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Fair Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		430		150
Fair Value [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	2.5
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	2.5
Fair Value [Member] | Targa Pipeline Partners LP [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			2.6
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			2.6
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		3,881.2		4,101.6
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	29		19.6
Liabilities from commodity derivative contracts	[1]	86.5		69.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Accounts receivable securitization facility		278.1		275
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		430		150
Fair Value [Member] | Level 2 [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		3,881.2		4,101.6
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	3		1.4
Liabilities from commodity derivative contracts	[1]	8.9		4.9
Fair Value [Member] | Level 3 [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	290.8
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	2.5
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	$ 2.5
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			2.6
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]			$ 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 13 – 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, which is carried at fair value. See Note 4 – Acquisitions and Divestitures.
[3]	We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value.

Fair Value Measurements, Change

Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions	9 Months Ended
	Sep. 30, 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	(293.3)
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	(290.8)	[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	(0.8)
Transfers out of Level 3	1.6	[1]
Settlements included in Revenue	0.4
Unrealized gain/(loss) included in OCI	(3.5)
Balance, end of period	(5.9)
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 September 30, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 –Acquisitions and Divestitures for discussion of the initial fair value.

Related Party Transactions - 90

Related Party Transactions - Targa (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Summary of transactions with Targa [Abstract]
Cash distributions to Targa based on IDR, general partner and limited partner ownership				$ 633.1	$ 542.6
Cash contributions from Targa related to limited partner ownership				1,587.5	1,167.2
Targa Resources Corp. [Member]
Summary of transactions with Targa [Abstract]
Targa billings of payroll and related costs included in operating expense		$ 54	$ 42.6	148.6	125
Targa allocation of general and administrative expense		43.2	40.1	126.6	117.7
Cash distributions to Targa based on IDR, general partner and limited partner ownership	[1]	222.6	178.9	624.7	395.1
Cash contributions from Targa related to limited partner ownership	[2]	14.7	210.7	1,587.5	1,167.2
Contributions from Targa Resources Corp		$ 0.3	$ 4.3	$ 32.5	$ 23.8
Percentage of general partner's interest maintained				2.00%
[1]	As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on general partner and limited partner ownership.
[2]	The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 12 – Partnership Units and Related Matters.

Related Party Transactions - 91

Related Party Transactions - Targa (Parenthetical) (Details) - Targa Resources Corp. [Member]	9 Months Ended
	Sep. 30, 2017
Related Party Transaction [Line Items]
Percentage of capital contribution towards partner's interest maintained	98.00%
Percentage of general partner's interest maintained	2.00%

Other Operating (Income) Expe92

Other Operating (Income) Expense (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Other Income And Expenses [Abstract]
Loss on sale or disposal of assets	[1]	$ 0.3	$ 4.7	$ 16.6	$ 5.7
Miscellaneous business tax		0.3	0.2	0.6	0.4
Total other operating (income) expense		$ 0.6	$ 4.9	$ 17.2	$ 6.1
[1]	Comprised primarily of a $16.1 million loss in the first quarter of 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) Expe93

Other Operating (Income) Expense (Parenthetical) (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Other Operating Income Expense [Line Items]
Loss on sale or disposal of assets	[1]	$ (0.3)		$ (4.7)	$ (16.6)	$ (5.7)
VGS [Member] | Disposal Group, Not Discontinued Operations [Member]
Other Operating Income Expense [Line Items]
Loss on sale or disposal of assets			$ (16.1)
[1]	Comprised primarily of a $16.1 million loss in the first quarter of 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 Inform94

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2017
Cash [Abstract]
Interest paid, net of capitalized interest	[1]	$ 154.5	$ 197.1
Income taxes paid, net of refunds		(4.9)	1.2
Non-cash investing activities [Abstract]
Deadstock commodity inventory transferred to property, plant and equipment		8.3	16.9
Impact of capital expenditure accruals on property, plant and equipment		118.3	(0.5)
Transfers from materials and supplies inventory to property, plant and equipment		2.8	1.9
Contribution of property, plant and equipment to investment in unconsolidated affiliates		1
Change in ARO liability and property, plant and equipment due to revised cash flow estimate		3.1	(9.2)
Non-cash financing activities [Abstract]
Cancellation of treasury units			0
Accrued distributions on unvested equity awards under share compensation arrangements		0	0.2
Permian Acquisition [Member]
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Acquisitions and Divestitures):
Contingent consideration recorded at the acquisition date		$ 416.3		$ 416.3
Treasury Units [Member]
Non-cash financing activities [Abstract]
Cancellation of treasury units			$ (10.4)
[1]	Interest capitalized on major projects was $8.3 million and $7.2 million for the nine months ended September 30, 2017 and 2016.

Supplemental Cash Flow Inform95

Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Supplemental Cash Flow Information [Abstract]
Interest capitalized on major projects	$ 8.3	$ 7.2

Segment Information, Revenues a

Segment Information, Revenues and Operating Margin (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)Segment	Sep. 30, 2016USD ($)
Segment Reporting Information [Line Items]
Number of segments | Segment			2
Revenues [Abstract]
Sales of commodities	$ 1,871.5	$ 1,398.7	$ 5,353.1	$ 3,882.9
Fees from midstream services	260.3	253.6	759	795.5
Revenues	2,131.8	1,652.3	6,112.1	4,678.4
Gathering and Processing [Member]
Revenues [Abstract]
Revenues	1,134.2	869.5	3,158	2,263.8
Operating margin	198.3	149.4	549.3	404.1
Logistics and Marketing [Member]
Revenues [Abstract]
Revenues	1,871.6	1,431.2	5,423.4	4,010.7
Operating margin	115.9	126	358.5	424.6
Other [Member]
Revenues [Abstract]
Revenues	(1)	11.2	3.9	56.9
Operating margin	(1)	11.2	3.9	56.9
Corporate and Elimination [Member]
Revenues [Abstract]
Revenues	(873)	(659.6)	(2,473.2)	(1,653)
Operating Segments [Member]
Revenues [Abstract]
Sales of commodities	1,871.5	1,398.7	5,353.1	3,882.9
Fees from midstream services	260.3	253.6	759	795.5
Revenues	2,131.8	1,652.3	6,112.1	4,678.4
Operating Segments [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	200.3	172.2	544.4	441.3
Fees from midstream services	148.5	120.6	399.3	360.9
Revenues	348.8	292.8	943.7	802.2
Operating Segments [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	1,672.2	1,215.3	4,804.8	3,384.7
Fees from midstream services	111.8	133	359.7	434.6
Revenues	1,784	1,348.3	5,164.5	3,819.3
Operating Segments [Member] | Other [Member]
Revenues [Abstract]
Sales of commodities	(1)	11.2	3.9	56.9
Revenues	(1)	11.2	3.9	56.9
Intersegment Eliminations [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	783.7	574.8	2,209.2	1,455.8
Fees from midstream services	1.7	1.9	5.1	5.8
Revenues	785.4	576.7	2,214.3	1,461.6
Intersegment Eliminations [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	80.6	76.3	237.8	176.3
Fees from midstream services	7	6.6	21.1	15.1
Revenues	87.6	82.9	258.9	191.4
Intersegment Eliminations [Member] | Corporate and Elimination [Member]
Revenues [Abstract]
Sales of commodities	(864.3)	(651.1)	(2,447)	(1,632.1)
Fees from midstream services	(8.7)	(8.5)	(26.2)	(20.9)
Revenues	$ (873)	$ (659.6)	$ (2,473.2)	$ (1,653)

Segment Information, Other Fina

Segment Information, Other Financial Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Mar. 01, 2017	Dec. 31, 2016
Other financial information [Abstract]
Total assets		$ 13,972.2		$ 13,972.2			$ 12,744.9
Goodwill		256.6		256.6		$ 46.6	$ 210
Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	13,972.2	$ 12,908.2	13,972.2	$ 12,908.2
Goodwill		256.6	393	256.6	393
Capital expenditures		378.7	134.6	987.7	426.5
Business acquisition		987.1		987.1
Operating Segments [Member] | Gathering and Processing [Member]
Other financial information [Abstract]
Total assets	[1]	10,644.3	10,047.3	10,644.3	10,047.3
Goodwill		256.6	393	256.6	393
Capital expenditures		295.9	97.1	730.7	271.3
Business acquisition		987.1		987.1
Operating Segments [Member] | Logistics and Marketing [Member]
Other financial information [Abstract]
Total assets	[1]	3,240.9	2,737.5	3,240.9	2,737.5
Capital expenditures		71	36.2	241.8	151.9
Operating Segments [Member] | Other [Member]
Other financial information [Abstract]
Total assets	[1]	30.8	47.2	30.8	47.2
Operating Segments [Member] | Corporate and Elimination [Member]
Other financial information [Abstract]
Total assets	[1]	56.2	76.2	56.2	76.2
Capital expenditures		$ 11.8	$ 1.3	$ 15.2	$ 3.3
[1]	Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

Segment Information, Revenues b

Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenue from External Customer [Line Items]
Sales of commodities	$ 1,871.5	$ 1,398.7	$ 5,353.1	$ 3,882.9
Fees from midstream services	260.3	253.6	759	795.5
Total revenues	2,131.8	1,652.3	6,112.1	4,678.4
Natural Gas [Member]
Revenue from External Customer [Line Items]
Sales of commodities	504.1	465.6	1,480.9	1,102
NGL [Member]
Revenue from External Customer [Line Items]
Sales of commodities	1,274.9	866.7	3,623.9	2,575.8
Condensate [Member]
Revenue from External Customer [Line Items]
Sales of commodities	44.9	35	135.9	96.2
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sales of commodities	48.6	20.2	108.5	52
Derivative Activities [Member]
Revenue from External Customer [Line Items]
Sales of commodities	(1)	11.2	3.9	56.9
Fractionating and Treating [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	29.8	33.2	92.8	94.8
Storage, Terminaling, Transportation and Export [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	75	89.7	247.8	316.3
Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	138	110.9	368.5	329.9
Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	$ 17.5	$ 19.8	$ 49.9	$ 54.5

Segment Information, Reconcilia

Segment Information, Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2016
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Depreciation and amortization expenses	$ (208.3)	$ (184)		$ (602.8)	$ (563.6)
General and administrative expenses	(46.6)	(44)		(139.4)	(132.3)
Impairment of property, plant and equipment	(378)	0		(378)	0
Impairment of goodwill	0	0	$ (24)	0	(24)
Interest expense, net	(51.9)	(57.9)		(169.5)	(171.2)
Other, net	126.6	(5.8)		78.4	5
Income (loss) before income taxes	(245)	(5.1)		(299.6)	(0.5)
Gathering and Processing [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	198.3	149.4		549.3	404.1
Logistics and Marketing [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	115.9	126		358.5	424.6
Other [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	$ (1)	$ 11.2		$ 3.9	$ 56.9