Targa Resources Partners (NGLS-PA) 10-Q 3 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2018
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	2,018
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 206.7	$ 124.7
Trade receivables, net of allowances of $0.1 and $0.1 million at March 31, 2018 and December 31, 2017	744.8	825.7
Inventories	96.7	204.5
Assets from risk management activities	63.2	37.9
Other current assets	31.3	55.8
Total current assets	1,142.7	1,248.6
Property, plant and equipment	14,762	14,198.6
Accumulated depreciation	(3,920.4)	(3,768.7)
Property, plant and equipment, net	10,841.6	10,429.9
Intangible assets, net	2,120.1	2,165.8
Goodwill, net	256.6	256.6
Long-term assets from risk management activities	41.4	23.2
Investments in unconsolidated affiliates	313.4	221.6
Other long-term assets	11.9	13.3
Total assets	14,727.7	14,359
Current liabilities:
Accounts payable and accrued liabilities	968.3	1,106.6
Accounts payable to Targa Resources Corp.	64.6	76.9
Liabilities from risk management activities	53.6	79.7
Current debt obligations	300	350
Total current liabilities	1,386.5	1,613.2
Long-term debt	4,629.2	4,268
Long-term liabilities from risk management activities	18.1	19.6
Deferred income taxes, net	24	24
Other long-term liabilities	568.1	576
Contingencies (see Note 15)
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 March 31, 2018 and December 31, 2017)	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 March 31, 2018 and December 31, 2017)	6,377.1	6,500.3
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of March 31, 2018 and December 31, 2017)	805.7	808.2
Accumulated other comprehensive income (loss)	45.3	(46)
Partners' Capital	7,348.7	7,383.1
Noncontrolling interests in subsidiaries	753.1	475.1
Total owners' equity	8,101.8	7,858.2
Total liabilities and owners' equity	$ 14,727.7	$ 14,359

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Trade receivables, allowances	$ 0.1	$ 0.1
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
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Sales of commodities (see Note 3)	$ 2,173.7	$ 1,858.1
Fees from midstream services (see Note 3)	281.9	254.5
Total revenues	2,455.6	2,112.6
Costs and expenses:
Product purchases (see Note 3)	1,941	1,654.2
Operating expenses	173.2	151.9
Depreciation and amortization expense	198.1	191.1
General and administrative expense	52.6	45.5
Other operating (income) expense	0.3	16.2
Income (loss) from operations	90.4	53.7
Other income (expense):
Interest income (expense), net	20.2	(58.6)
Equity earnings (loss)	1.5	(12.6)
Gain (loss) from financing activities	0	0
Change in contingent considerations	(56.1)	(3.3)
Other, net	0	(5.2)
Income (loss) before income taxes	56	(26)
Income tax (expense) benefit	0	4.7
Net income (loss)	56	(21.3)
Less: Net income (loss) attributable to noncontrolling interests	13.2	6
Net income (loss) attributable to Targa Resources Partners LP	42.8	(27.3)
Net income attributable to preferred limited partners	2.8	2.8
Net income (loss) attributable to general partner	0.8	(0.6)
Net income (loss) attributable to common limited partners	39.2	(29.5)
Net income (loss) attributable to Targa Resources Partners LP	$ 42.8	$ (27.3)

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income (loss)	$ 56	$ (21.3)
Other comprehensive income (loss):
Other comprehensive income (loss)	91.3	72.3
Comprehensive income (loss)	147.3	51
Less: Comprehensive income (loss) attributable to noncontrolling interests	13.2	6
Comprehensive income (loss) attributable to Targa Resources Partners LP	134.1	45
Commodity Contracts [Member]
Other comprehensive income (loss):
Change in fair value	64.6	66.2
Settlements reclassified to revenues	$ 26.7	$ 6.1

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, 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Targa Resources Corp.	655	$ 0	$ 641.9	$ 13.1	0	0	0
Contributions from Targa Resources Corp. (in units)		0	0	0
Distributions to noncontrolling interests	(9.7)	$ 0	$ 0	$ 0	0	0	(9.7)
Contributions from noncontrolling interests	8.9	0	0	0	0	0	8.9
Other comprehensive income (loss)	72.3	0	0	0	72.3	0	0
Net income (loss)	(21.3)	2.8	(29.5)	(0.6)	0	0	6
Distributions	(198.1)	(2.8)	(191.4)	(3.9)	0	0	0
Balance at Mar. 31, 2017	7,657.7	$ 120.6	$ 6,360.9	$ 805.3	10.5	0	360.4
Balance (in units) at Mar. 31, 2017		5,000	275,168	5,629
Balance at Dec. 31, 2017	7,858.2	$ 120.6	$ 6,500.3	$ 808.2	(46)	0	475.1
Balance (in units) at Dec. 31, 2017		5,000	275,168	5,629
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Targa Resources Corp.	60	$ 0	$ 58.8	$ 1.2	0	0	0
Contributions from Targa Resources Corp. (in units)		0	0	0
Acquisition of related party (see Note 14)	1.2	$ 0	$ 0	$ 0	0	0	1.2
Distributions to noncontrolling interests	(16.5)	0	0	0	0	0	(16.5)
Contributions from noncontrolling interests	280.1	0	0	0	0	0	280.1
Other comprehensive income (loss)	91.3	0	0	0	91.3	0	0
Net income (loss)	56	2.8	39.2	0.8	0	0	13.2
Distributions	(228.5)	(2.8)	(221.2)	(4.5)	0	0	0
Balance at Mar. 31, 2018	$ 8,101.8	$ 120.6	$ 6,377.1	$ 805.7	$ 45.3	$ 0	$ 753.1
Balance (in units) at Mar. 31, 2018		5,000	275,168	5,629

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net income (loss)		$ 56	$ (21.3)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		2.3	2.4
Depreciation and amortization expense		198.1	191.1
Accretion of asset retirement obligations		0.9	1.3
Increase (decrease) in redemption value of mandatorily redeemable preferred interests		(72.5)	2.5
Deferred income tax expense (benefit)		0	(0.5)
Equity (earnings) loss of unconsolidated affiliates		(1.5)	12.6
Distributions of earnings received from unconsolidated affiliates		4.2	2.7
Risk management activities		30.1	8.5
(Gain) loss on sale or disposition of assets	[1]	(0.1)	16.1
Change in contingent considerations included in Other expense (income)		56.1	3.3
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		95	140.6
Inventories		110.2	53.7
Accounts payable and other liabilities		(124.6)	(99.8)
Net cash provided by operating activities		354.2	313.2
Cash flows from investing activities
Outlays for property, plant and equipment		(595.9)	(144.2)
Outlays for business acquisition, net of cash acquired		0	(480.8)
Investments in unconsolidated affiliates		(88)	(0.5)
Return of capital from unconsolidated affiliates		1.5	0
Other, net		5.1	0
Net cash used in investing activities		(677.3)	(625.5)
Debt obligations:
Proceeds from borrowings under credit facility		600	480
Repayments of credit facility		(240)	(630)
Proceeds from borrowings under accounts receivable securitization facility		0	75
Repayments of accounts receivable securitization facility		(50)	(65)
Costs incurred in connection with financing arrangements		0	(0.1)
Contributions from general partner		1.2	13.1
Contributions from TRC		58.8	641.9
Contributions from noncontrolling interests		280.1	8.9
Distributions to noncontrolling interests		(16.5)	(9.7)
Distributions to unitholders		(228.5)	(198.1)
Net cash provided by financing activities		405.1	316
Net change in cash and cash equivalents		82	3.7
Cash and cash equivalents, beginning of period		124.7	68
Cash and cash equivalents, end of period		$ 206.7	$ 71.7
[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	3 Months Ended
	Mar. 31, 2018
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. Our common units are wholly owned by TRC and no longer publicly traded as a result of TRC’s acquisition of our outstanding common units that it and its subsidiaries did not already own in 2016. 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.” 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	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	Note 2 — Basis of Presentation We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report. The unaudited consolidated financial statements for the three months ended March 31, 2018 include all adjustments that we believe are necessary for a fair statement of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. Our financial results for the three months ended March 31, 2018 are not necessarily indicative of the results that may be expected for the full year.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies Recent Accounting Pronouncements Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In March 2018, the FASB approved an additional transition method that, if elected, would allow entities to apply the new leases standard to all new leases entered into after January 1, 2019 and all existing lease contracts as of January 1, 2019 through a cumulative adjustment to retained earnings. We expect to adopt Topic 842 on January 1, 2019, and expect to elect the land easement practical expedient as well as the optional additional transition method. We are currently in the process of gathering a complete population of our lease arrangements, and are evaluating the impact of the new standard on our consolidated financial statements. 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. Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following table summarizes the effects of adoption on our consolidated financial statements: Three Months Ended March 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,260.1 $ (86.4 ) $ 2,173.7 Fees from midstream services 288.4 (6.5 ) 281.9 Total revenues 2,548.5 (92.9 ) 2,455.6 Costs and expenses: Product purchases 2,033.9 (92.9 ) 1,941.0 Income from operations 90.4 — 90.4 Income (loss) before income taxes 56.0 — 56.0 Net income (loss) $ 56.0 $ — $ 56.0 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 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) Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Other Income In February Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) Revenue from Contracts with Customers (Topic 606), These amendments were effective for us on January 1, 2018 and were adopted by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2018. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220). Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. Besides those noted below, there were no other significant updates or revisions to our policies during the three months ended March 31, 2018. Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation, which is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value to the customer of the days of service transferred to date, relative to the remaining days of service promised under the contract. The transaction price of such contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When the Company is entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, the Company measures the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, the Company defines the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which the Company is entitled to, is resolved, and can be included in that month or quarter’s revenue. Significant Judgments Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, the Company estimates the total consideration, which we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. The Company’s estimate of total consideration is reassessed each reporting period until contract completion. For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment.

Newly-Formed Joint Ventures and

Newly-Formed Joint Ventures and Acquisitions	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Newly-Formed Joint Ventures and Acquisitions	Note 4 –Newly-Formed Joint Ventures and Acquisitions Joint Ventures Grand Prix Joint Venture In May 2017, we announced plans to construct Grand Prix, a new common carrier 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 a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, Concurrent with the sale of the 25% 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 whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. In March 2018, we announced an extension of Grand Prix into southern Oklahoma. The pipeline expansion is supported by long-term commitments for both transportation and fractionation services from our existing and future processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa. The total cost for Grand Prix, including the extension into southern Oklahoma, is expected to be approximately $1.7 billion. Cayenne In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“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 commenced operations in December 2017. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Cayenne Joint Venture. Gulf Coast Express Joint Venture In December 2017, Gulf Coast Express Pipeline (“GCX”), . The pipeline 50 In owner 1. ls. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture. Little Missouri 4 Joint Venture In January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at the Partnership’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed at the end of the fourth quarter of 2018. The Partnership will manage construction of, and operate, the LM4 Plant. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Little Missouri 4 Joint Venture. DevCo Joint Ventures In February 2018 , we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in Grand Prix Development LLC (“Grand Prix DevCo JV”), which owns a 20% interest in the Grand Prix Joint Venture (not including the extension into southern Oklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“ GCX DevCo JV”), which owns our 25% interest in GCX , and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management, construction and operation of Grand Prix and Train 6. The following diagram displays the ownership structure of the DevCo JVs: For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa will control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 is expected to begin operations in the first quarter of 2019. Grand Prix is expected to be in service in the second quarter of 2019 . X is expected to be in service in the fourth quarter of 2019, pending the receipt of necessary regulatory approvals. We . We continue to account for Grand Prix and Train 6 on a consolidated basis in o an equity method investment as disclosed in Note 7 – Investments in Unconsolidated Affiliates. Acquisitions Permian Acquisition On March 1, 2017, we 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 May 2018 and May 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017. The portion of the earn-out due in 2018 expired with no required payment. Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statements of Operations information for the three months ended March 31, 2017 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. March 31, 2017 Pro Forma Revenues $ 2,126.7 Net income (loss) (23.4 ) 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 $5.1 million of acquisition-related costs incurred as of March 31, 2017 from pro forma net income for the three months ended March 31, 2017. Pro forma net income for the three months ended March 31, 2017 was adjusted to include those charges. 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 aggregate potential earn-out payments in May 2018 and May 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 the liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the three months ended March 31, 2018 and 2017, we recognized $56.0 million and $3.2 million as Other income related to the change in fair value of the contingent consideration The portion of the earn-out due in 2018 expired with no required payment. As of March 31, 2018, the fair value of the second potential earn-out payment of $373.0 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 10 – Other Long-term Liabilities and Note 13 – Fair Value Measurements for additional discussion of the fair value methodology.

Inventories

Inventories	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories March 31, 2018 December 31, 2017 Commodities $ 79.6 $ 191.6 Materials and supplies 17.1 12.9 $ 96.7 $ 204.5

Property, Plant and Equipment a

Property, Plant and Equipment and Intangible Assets	3 Months Ended
	Mar. 31, 2018
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	Note 6 — Property, Plant and Equipment and Intangible Assets March 31, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,154.4 $ 7,037.2 5 to 20 Processing and fractionation facilities 3,678.3 3,563.0 5 to 25 Terminaling and storage facilities 1,252.3 1,244.1 5 to 25 Transportation assets 343.6 343.6 10 to 25 Other property, plant and equipment 312.1 303.5 3 to 25 Land 144.3 125.7 — Construction in progress 1,877.0 1,581.5 — Property, plant and equipment 14,762.0 14,198.6 Accumulated depreciation (3,920.4 ) (3,768.7 ) Property, plant and equipment, net $ 10,841.6 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (616.5 ) (570.8 ) Intangible assets, net $ 2,120.1 $ 2,165.8 Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition and the acquisition of the Flag City Plant assets in SouthTX 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. We are amortizing these assets over lives ranging from 10 to 20 years using a method that closely reflects the cash flow pattern underlying their intangible asset valuation, or the straight-line method, if a reliably determinable pattern of amortization could not be identified. The estimated annual amortization expense for intangible assets is approximately $182.6 million, $171.6 million, $159.4 million, $149.5 million and $141.2 million for each of the years 2018 through 2022. The changes in our intangible assets are as follows: Balance at December 31, 2017 $ 2,165.8 Amortization (45.7 ) Balance at March 31, 2018 $ 2,120.1 Subsequent Event On May 1, 2018, we executed an agreement to sell our inland marine barge business to Kirby Corp. for approximately $69.3 million. Subject to customary regulatory approvals and other closing conditions, the transaction is expected to close during the second quarter of 2018. Subsequent to the closing of the sale, we will continue to own and operate two ocean-going barges.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2018
Equity Method Investments And Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Note 7 – 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, which owns a cogeneration facility, (together the “T2 Joint Ventures”); • a 50% operated ownership interest in the Cayenne ; • a 25% non-operated ownership interest in GCX; and • a 50% operated ownership interest in Little Missouri 4. 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 T2 Joint Ventures The T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization). The carrying values of the T2 Joint Venture Cayenne, GCX and Little Missouri 4 Joint Ventures See Note 4 – Newly-Formed Joint Ventures and Acquisitions for discussion of the formation of our Cayenne Joint Venture, GCX Joint Venture and Little Missouri 4 Joint Venture. The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Contributions (2) Balance at March 31, 2018 GCF $ 45.8 $ 4.2 $ (5.7 ) $ — $ 44.3 T2 LaSalle 54.1 (1.3 ) — 0.1 52.9 T2 Eagle Ford 109.2 (2.6 ) — — 106.6 T2 EF Cogen 3.9 (0.4 ) — — 3.5 Cayenne 8.6 1.6 — 2.1 12.3 GCX — — — 69.5 69.5 Little Missouri 4 — — (8.0 ) 32.3 24.3 Total $ 221.6 $ 1.5 $ (13.7 ) $ 104.0 $ 313.4 _________________ (1) Includes $1.5 million in distributions received from GCF in excess of our share of cumulative earnings for the three months ended March 31, 2018. 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. Also includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. (2) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	3 Months Ended
	Mar. 31, 2018
Payables And Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Note 8 — Accounts Payable and Accrued Liabilities March 31, 2018 December 31, 2017 Commodities $ 593.0 $ 711.9 Other goods and services 254.7 286.9 Interest 63.4 54.1 Permian Acquisition contingent consideration, estimated current portion — 6.8 Income and other taxes 28.3 26.3 Other 28.9 20.6 $ 968.3 $ 1,106.6 Accounts payable and accrued liabilities includes $56.6 million and $49.7 million of liabilities to creditors to whom we have issued checks that remained outstanding as of March 31, 2018 and December 31, 2017. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value of the first potential earn-out payment that would have been due in May 2018. The estimated remaining portion that would be payable in May 2019 is recorded within Other long-term liabilities on our Consolidated Balance Sheets.

Debt Obligations

Debt Obligations	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt Obligations	Note 9 — Debt Obligations March 31, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2018 $ 300.0 $ 350.0 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (1) 380.0 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 749.4 749.4 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 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.4 0.4 4,658.0 4,298.0 Debt issuance costs, net of amortization (28.8 ) (30.0 ) Long-term debt 4,629.2 4,268.0 Total debt obligations $ 4,929.2 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 25.9 $ 27.2 (1) As of March 31, 2018, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,194.1 million. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.5% 3.8% Accounts receivable securitization facility 2.6% - 2.9% 2.6% Compliance with Debt Covenants As of March 31, 2018, we were in compliance with the covenants contained in our various debt agreements. Subsequent Event In April 2018, we issued $1.0 billion aggregate principal amount of 5 ⅞ ⅞

Other Long-term Liabilities

Other Long-term Liabilities	3 Months Ended
	Mar. 31, 2018
Other Liabilities Noncurrent [Abstract]
Other Long-term Liabilities	Note 10 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: March 31, 2018 December 31, 2017 Asset retirement obligations $ 52.5 $ 50.3 Mandatorily redeemable preferred interests 4.2 76.2 Deferred revenue 135.2 136.2 Permian Acquisition contingent consideration, noncurrent portion 373.0 310.2 Other liabilities 3.2 3.1 Total long-term liabilities $ 568.1 $ 576.0 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, 2017 $ 50.3 Change in cash flow estimate 2.1 Accretion expense 0.9 Retirement of ARO (0.8 ) Balance at March 31, 2018 $ 52.5 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. As 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 March 31, 2018. The following table shows the changes attributable to mandatorily redeemable preferred interests: Balance at December 31, 2017 $ 76.2 Income attributable to mandatorily redeemable preferred interests 0.5 Change in estimated redemption value included in interest (income) expense, net (72.5 ) Balance at March 31, 2018 $ 4.2 In February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on or after January 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. During the three months ended March 31, 2018, the $72.5 million change in the estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to the amendments. 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., then a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (the “Splitter Agreement”) under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (the “Channelview Splitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d 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 in the second quarter of 2018, and has an estimated total cost of approximately $140 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 January 2018, Vitol US Holding Co. acquired Noble Americas Corp. 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. As the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023. The following table shows the components of deferred revenue: March 31, 2018 December 31, 2017 Splitter agreement $ 86.0 $ 86.0 Gas contract amendment 44.1 44.7 Other deferred revenue 5.1 5.5 Total deferred revenue $ 135.2 $ 136.2 The following table shows the changes in deferred revenue: Balance at December 31, 2017 $ 136.2 Additions — Revenue recognized (1.0 ) Balance at March 31, 2018 $ 135.2 Permian Acquisition 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 For the period from the acquisition date to December 31, 2017, the fair value of this liability decreased by $99.3 million, bringing the total Permian Acquisition contingent consideration to $317.0 million at December 31, 2017. The portion of the earn-out due in 2018 expired with no required payment. As of March 31, 2018, the fair value of the second potential earn-out payment of $373.0 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. The increase in fair value of the contingent consideration during the three months ended March 31, 2018 was primarily related to an increase in underlying forecasted volumes for the remainder of the earn-out period and a shorter term over which such projections are discounted. See Note 13 – Fair Value Measurements for additional discussion of the fair value methodology. The following table shows the changes in contingent consideration: Balance at December 31, 2017 $ 317.0 Increase in fair value due to factors occurring after acquisition date 56.0 Balance at March 31, 2018 373.0 Less: Current portion — Long-term balance at March 31, 2018 $ 373.0

Partnership Units and Related M

Partnership Units and Related Matters	3 Months Ended
	Mar. 31, 2018
Partners Capital [Abstract]
Partnership Units and Related Matters	Note 11 — Partnership Units and Related Matters Distributions TRC is entitled to receive all Partnership distributions after payment of preferred distributions each quarter. The following details the distributions declared and/or paid by us for the three months ended March 31, 2018: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. March 31, 2018 May 11, 2018 $ 229.7 $ 226.9 December 31, 2017 February 12, 2018 228.5 225.7 Contributions All capital contributions continue to be allocated 98% to the limited partner and 2% to our general partner; however, no units will be issued for those contributions. During the three months ended March 31, 2018, TRC made total capital contributions to us of $60.0 million. Preferred Units Our Preferred Units rank senior to our common units with respect to distribution rights. Distributions on our 5,000,000 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 of distributions to the holders of preferred units (“Preferred Unitholders”) for the three months ended March 31, 2018. The Preferred Units are reported as noncontrolling interests in our financial statements. Subsequent Event In April 2018, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions which will be paid on May 15, 2018.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 12 — 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. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues. At March 31, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2018 2019 2020 Natural Gas Swaps MMBtu/d 170,739 131,506 - Natural Gas Basis Swaps MMBtu/d 138,009 78,062 10,417 Natural Gas Options MMBtu/d 5,096 - - NGL Swaps Bbl/d 22,779 13,449 4,567 NGL Futures Bbl/d 8,923 1,383 - NGL Options Bbl/d 1,310 410 - Condensate Swaps Bbl/d 4,990 2,653 - Condensate Options Bbl/d 590 590 - 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 March 31, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 61.1 $ 43.3 $ 37.9 $ 78.6 Long-term 40.5 13.2 23.2 18.7 Total derivatives designated as hedging instruments $ 101.6 $ 56.5 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.1 $ 10.3 $ — $ 1.1 Long-term 0.9 4.9 — 0.9 Total derivatives not designated as hedging instruments $ 3.0 $ 15.2 $ — $ 2.0 Total current position $ 63.2 $ 53.6 $ 37.9 $ 79.7 Total long-term position 41.4 18.1 23.2 19.6 Total derivatives $ 104.6 $ 71.7 $ 61.1 $ 99.3 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 March 31, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 63.2 $ (51.2 ) $ 5.8 $ 39.6 $ (21.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.4 ) - - (2.4 ) 63.2 (53.6 ) 5.8 39.6 (24.2 ) Long Term Position Counterparties with offsetting positions or collateral 41.4 (16.9 ) - 32.7 (8.2 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (1.2 ) - - (1.2 ) 41.4 (18.1 ) - 32.7 (9.4 ) Total Derivatives Counterparties with offsetting positions or collateral 104.6 (68.1 ) 5.8 72.3 (30.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.6 ) - - (3.6 ) $ 104.6 $ (71.7 ) $ 5.8 $ 72.3 $ (33.6 ) Gross Presentation Pro forma net presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 ) 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 asset of $32.9 million as of March 31, 2018. 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 March 31, Hedging Relationships 2018 2017 Commodity contracts $ 64.6 $ 66.2 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended March 31, Location of Gain (Loss) 2018 2017 Revenues $ (26.7 ) $ (6.1 ) Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended March 31, as Hedging Instruments Derivatives 2018 2017 Commodity contracts Revenue $ (10.8 ) $ (0.8 ) Based on valuations as of March 31, 2018, we expect to reclassify commodity hedge-related deferred gains of $45.2 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2020, with $17.9 million of gains to be reclassified over the next twelve months. See Note 13 – Fair Value Measurements and Note 19 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 13 — 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 March 31, 2018, a net asset position of $32.9 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 $42.9 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 $108.8 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: March 31, 2018 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) $ 104.3 $ 104.3 $ — $ 103.9 $ 0.4 Liabilities from commodity derivative contracts (1) 71.4 71.4 — 67.7 3.7 Permian Acquisition contingent consideration (2) 373.0 373.0 — — 373.0 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 206.7 206.7 — — — TRP Revolver 380.0 380.0 — 380.0 — Senior unsecured notes 4,278.0 4,257.0 — 4,257.0 — Accounts receivable securitization facility 300.0 300.0 — 300.0 — December 31, 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) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — (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 12– 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 – Newly-Formed Joint Ventures and Acquisitions. (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 March 31, 2018, we had 12 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 our 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, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of TPL contingent consideration - (0.1 ) Change in fair value of Permian Acquisition contingent consideration (1) - (56.0 ) New Level 3 derivative instruments (0.1 ) - Settlements included in Revenue (0.4 ) - Unrealized gain/(loss) included in OCI 0.9 - Balance, March 31, 2018 $ (3.4 ) $ (375.5 ) (1) Represents the change in fair value between December 31, 2017 and March 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures and Acquisitions for discussion of the initial fair value.

Related Party Transactions - Ta

Related Party Transactions - Targa	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions - Targa	Note 14 — 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 March 31, 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 59.5 $ 47.0 Targa allocation of general and administrative expense 47.3 42.0 Cash distributions to Targa based on general partner and limited partner ownership 225.7 195.3 Cash contributions from Targa related to limited partner ownership (1) 58.8 641.9 Cash contributions from Targa to maintain its 2% general partner ownership 1.2 13.1 _______________________ (1) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 11 – Partnership Units and Related Matters. Relationship with Sajet Resources LLC In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Certain directors and executive officers of Targa are also directors and executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of Targa’s pre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest in Sajet We provide general and administrative services to Sajet and are reimbursed for these amounts. Services provided to Sajet totaled less than $0.1 million in January and February of 2018. In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018. As of March 2018, Sajet is accounted for on a consolidated basis in our consolidated financial statements.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Contingencies	Note 15 – Contingencies Legal Proceedings We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Revenue

Revenue	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue	Note 16 – Revenue Fixed consideration allocated to remaining performance obligations The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated . These contracts are comprised primarily of fractionation, export, terminaling and storage agreements. 2018 2019 2020 and after Fixed consideration to be recognized as of March 31, 2018 $ 322.1 $ 368.1 $ 1,400.0 In accordance with the optional exemptions that we elected to apply, the amounts presented in the table exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy and the estimated remaining duration of such contracts ranges from 1 to 25 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter. For additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

Other Operating (Income) Expens

Other Operating (Income) Expense	3 Months Ended
	Mar. 31, 2018
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 March 31, 2018 2017 (Gain) loss on sale or disposal of assets (1) $ (0.1 ) $ 16.1 Miscellaneous business tax 0.3 0.1 Other 0.1 — $ 0.3 $ 16.2 _________________ _________ (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	3 Months Ended
	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 18 — Supplemental Cash Flow Information Three Months Ended March 31, 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 39.4 $ 53.5 Income taxes paid, net of refunds 0.2 (0.1 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 1.7 $ 8.3 Impact of capital expenditure accruals on property, plant and equipment (22.3 ) 30.0 Transfers from materials and supplies inventory to property, plant and equipment 0.4 0.4 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 2.1 1.7 Non-cash financing activities: Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures and Acquisitions): Contingent consideration recorded at the acquisition date $ — $ 461.6 Purchase consideration payable recorded for the Permian Acquisition — 90.0 Non-cash balance sheet movements related to acquisition of related party: Intercompany payable 1.4 — Noncontrolling interest 1.2 — __________________ (1) Interest capitalized on major projects was $9.6 million and $1.7 million for the three months ended March 31, 2018 and 2017.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2018
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 reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. 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 (including exposure to the SCOOP and STACK plays) 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 the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment includes Grand Prix, which is currently under construction. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables: Three Months Ended March 31, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 265.2 $ 1,926.3 $ (17.8 ) $ — $ 2,173.7 Fees from midstream services 161.3 120.6 — — 281.9 426.5 2,046.9 (17.8 ) — 2,455.6 Intersegment revenues Sales of commodities 866.5 55.7 — (922.2 ) — Fees from midstream services 1.9 6.9 — (8.8 ) — 868.4 62.6 — (931.0 ) — Revenues $ 1,294.9 $ 2,109.5 $ (17.8 ) $ (931.0 ) $ 2,455.6 Operating margin $ 220.8 $ 138.4 $ (17.8 ) $ — $ 341.4 Other financial information: Total assets (1) $ 10,908.5 $ 3,595.1 $ 103.0 $ 121.1 $ 14,727.7 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 273.2 $ 251.0 $ — $ 33.8 $ 558.0 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Three Months Ended March 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 166.7 $ 1,692.4 $ (1.0 ) $ — $ 1,858.1 Fees from midstream services 118.2 136.3 — — 254.5 284.9 1,828.7 (1.0 ) — 2,112.6 Intersegment revenues Sales of commodities 713.0 75.4 — (788.4 ) — Fees from midstream services 1.9 7.0 — (8.9 ) — 714.9 82.4 — (797.3 ) — Revenues $ 999.8 $ 1,911.1 $ (1.0 ) $ (797.3 ) $ 2,112.6 Operating margin $ 177.4 $ 130.1 $ (1.0 ) $ — $ 306.5 Other financial information: Total assets (1) $ 10,780.4 $ 2,687.2 $ 44.8 $ 57.4 $ 13,569.8 Goodwill $ 369.0 $ — $ — $ — $ 369.0 Capital expenditures $ 139.2 $ 34.6 $ — $ 0.8 $ 174.6 ____________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 470.1 $ 481.7 NGL 1,607.3 1,319.7 Condensate 86.9 43.6 Petroleum products 48.2 19.8 2,212.5 1,864.8 Non-customer revenue: Derivative activities - Hedge (28.0 ) (5.9 ) Derivative activities - Non-hedge (1) (10.8 ) (0.8 ) (38.8 ) (6.7 ) Total sales of commodities 2,173.7 1,858.1 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 31.1 31.0 Storage, terminaling, transportation and export 88.7 99.7 Gathering and processing 152.1 107.7 Other 10.0 16.1 Total fees from midstream services 281.9 254.5 Total revenues $ 2,455.6 $ 2,112.6 __________________________________________________________________________________________ (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented: Three Months Ended March 31, 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 220.8 $ 177.4 Logistics and Marketing operating margin 138.4 130.1 Other operating margin (17.8 ) (1.0 ) Depreciation and amortization expenses (198.1 ) (191.1 ) General and administrative expenses (52.6 ) (45.5 ) Interest income (expense), net 20.2 (58.6 ) Other, net (54.9 ) (37.3 ) Income (loss) before income taxes $ 56.0 $ (26.0 )

Significant Accounting Polici27

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In March 2018, the FASB approved an additional transition method that, if elected, would allow entities to apply the new leases standard to all new leases entered into after January 1, 2019 and all existing lease contracts as of January 1, 2019 through a cumulative adjustment to retained earnings. We expect to adopt Topic 842 on January 1, 2019, and expect to elect the land easement practical expedient as well as the optional additional transition method. We are currently in the process of gathering a complete population of our lease arrangements, and are evaluating the impact of the new standard on our consolidated financial statements. 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. Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following table summarizes the effects of adoption on our consolidated financial statements: Three Months Ended March 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,260.1 $ (86.4 ) $ 2,173.7 Fees from midstream services 288.4 (6.5 ) 281.9 Total revenues 2,548.5 (92.9 ) 2,455.6 Costs and expenses: Product purchases 2,033.9 (92.9 ) 1,941.0 Income from operations 90.4 — 90.4 Income (loss) before income taxes 56.0 — 56.0 Net income (loss) $ 56.0 $ — $ 56.0 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 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) Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Other Income In February Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) Revenue from Contracts with Customers (Topic 606), These amendments were effective for us on January 1, 2018 and were adopted by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2018. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220).
Revenue Recognition	Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation, which is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value to the customer of the days of service transferred to date, relative to the remaining days of service promised under the contract. The transaction price of such contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When the Company is entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, the Company measures the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, the Company defines the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which the Company is entitled to, is resolved, and can be included in that month or quarter’s revenue. Significant Judgments Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, the Company estimates the total consideration, which we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. The Company’s estimate of total consideration is reassessed each reporting period until contract completion. For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment.

Significant Accounting Polici28

Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Summary of Effect of Adoption on Consolidated Financial Statements	The following table summarizes the effects of adoption on our consolidated financial statements: Three Months Ended March 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,260.1 $ (86.4 ) $ 2,173.7 Fees from midstream services 288.4 (6.5 ) 281.9 Total revenues 2,548.5 (92.9 ) 2,455.6 Costs and expenses: Product purchases 2,033.9 (92.9 ) 1,941.0 Income from operations 90.4 — 90.4 Income (loss) before income taxes 56.0 — 56.0 Net income (loss) $ 56.0 $ — $ 56.0

Newly-Formed Joint Ventures a29

Newly-Formed Joint Ventures and Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Pro Forma Consolidated Information of Operations	The following summarized unaudited pro forma Consolidated Statements of Operations information for the three months ended March 31, 2017 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. March 31, 2017 Pro Forma Revenues $ 2,126.7 Net income (loss) (23.4 )

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Components of Inventories	March 31, 2018 December 31, 2017 Commodities $ 79.6 $ 191.6 Materials and supplies 17.1 12.9 $ 96.7 $ 204.5

Property, Plant and Equipment31

Property, Plant and Equipment and Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2018
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	March 31, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,154.4 $ 7,037.2 5 to 20 Processing and fractionation facilities 3,678.3 3,563.0 5 to 25 Terminaling and storage facilities 1,252.3 1,244.1 5 to 25 Transportation assets 343.6 343.6 10 to 25 Other property, plant and equipment 312.1 303.5 3 to 25 Land 144.3 125.7 — Construction in progress 1,877.0 1,581.5 — Property, plant and equipment 14,762.0 14,198.6 Accumulated depreciation (3,920.4 ) (3,768.7 ) Property, plant and equipment, net $ 10,841.6 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (616.5 ) (570.8 ) Intangible assets, net $ 2,120.1 $ 2,165.8
Schedule of Changes in Intangible Assets	The changes in our intangible assets are as follows: Balance at December 31, 2017 $ 2,165.8 Amortization (45.7 ) Balance at March 31, 2018 $ 2,120.1

Investments in Unconsolidated32

Investments in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2018
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: Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Contributions (2) Balance at March 31, 2018 GCF $ 45.8 $ 4.2 $ (5.7 ) $ — $ 44.3 T2 LaSalle 54.1 (1.3 ) — 0.1 52.9 T2 Eagle Ford 109.2 (2.6 ) — — 106.6 T2 EF Cogen 3.9 (0.4 ) — — 3.5 Cayenne 8.6 1.6 — 2.1 12.3 GCX — — — 69.5 69.5 Little Missouri 4 — — (8.0 ) 32.3 24.3 Total $ 221.6 $ 1.5 $ (13.7 ) $ 104.0 $ 313.4 _________________ (1) Includes $1.5 million in distributions received from GCF in excess of our share of cumulative earnings for the three months ended March 31, 2018. 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. Also includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. (2) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4

Accounts Payable and Accrued 33

Accounts Payable and Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2018
Payables And Accruals [Abstract]
Schedule of Accounts Payable and Accrued Liabilities	March 31, 2018 December 31, 2017 Commodities $ 593.0 $ 711.9 Other goods and services 254.7 286.9 Interest 63.4 54.1 Permian Acquisition contingent consideration, estimated current portion — 6.8 Income and other taxes 28.3 26.3 Other 28.9 20.6 $ 968.3 $ 1,106.6

Debt Obligations (Tables)

Debt Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Outstanding Debt	March 31, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2018 $ 300.0 $ 350.0 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (1) 380.0 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 749.4 749.4 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 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.4 0.4 4,658.0 4,298.0 Debt issuance costs, net of amortization (28.8 ) (30.0 ) Long-term debt 4,629.2 4,268.0 Total debt obligations $ 4,929.2 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 25.9 $ 27.2 (1) As of March 31, 2018, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,194.1 million.
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 three months ended March 31, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.5% 3.8% Accounts receivable securitization facility 2.6% - 2.9% 2.6%

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	3 Months Ended
	Mar. 31, 2018
Other Liabilities Noncurrent [Abstract]
Other Long-term Liabilities	Other long-term liabilities are comprised of the following obligations: March 31, 2018 December 31, 2017 Asset retirement obligations $ 52.5 $ 50.3 Mandatorily redeemable preferred interests 4.2 76.2 Deferred revenue 135.2 136.2 Permian Acquisition contingent consideration, noncurrent portion 373.0 310.2 Other liabilities 3.2 3.1 Total long-term liabilities $ 568.1 $ 576.0
Changes in Aggregate Asset Retirement Obligations	The changes in our ARO are as follows Balance at December 31, 2017 $ 50.3 Change in cash flow estimate 2.1 Accretion expense 0.9 Retirement of ARO (0.8 ) Balance at March 31, 2018 $ 52.5
Schedule of Changes in Long-term Liability Attributable to Mandatorily Redeemable Preferred Interests	The following table shows the changes attributable to mandatorily redeemable preferred interests: Balance at December 31, 2017 $ 76.2 Income attributable to mandatorily redeemable preferred interests 0.5 Change in estimated redemption value included in interest (income) expense, net (72.5 ) Balance at March 31, 2018 $ 4.2
Components of Deferred Revenue	The following table shows the components of deferred revenue: March 31, 2018 December 31, 2017 Splitter agreement $ 86.0 $ 86.0 Gas contract amendment 44.1 44.7 Other deferred revenue 5.1 5.5 Total deferred revenue $ 135.2 $ 136.2
Changes in Deferred Revenue	The following table shows the changes in deferred revenue: Balance at December 31, 2017 $ 136.2 Additions — Revenue recognized (1.0 ) Balance at March 31, 2018 $ 135.2
Schedule of Changes in Permian Acquisition Contingent Consideration	The following table shows the changes in contingent consideration: Balance at December 31, 2017 $ 317.0 Increase in fair value due to factors occurring after acquisition date 56.0 Balance at March 31, 2018 373.0 Less: Current portion — Long-term balance at March 31, 2018 $ 373.0

Partnership Units and Related36

Partnership Units and Related Matters (Tables)	3 Months Ended
	Mar. 31, 2018
Partners Capital [Abstract]
Schedule of Distributions	The following details the distributions declared and/or paid by us for the three months ended March 31, 2018: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. March 31, 2018 May 11, 2018 $ 229.7 $ 226.9 December 31, 2017 February 12, 2018 228.5 225.7

Derivative Instruments and He37

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Notional Volume of Commodity Hedges	At March 31, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2018 2019 2020 Natural Gas Swaps MMBtu/d 170,739 131,506 - Natural Gas Basis Swaps MMBtu/d 138,009 78,062 10,417 Natural Gas Options MMBtu/d 5,096 - - NGL Swaps Bbl/d 22,779 13,449 4,567 NGL Futures Bbl/d 8,923 1,383 - NGL Options Bbl/d 1,310 410 - Condensate Swaps Bbl/d 4,990 2,653 - Condensate Options Bbl/d 590 590 -
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 March 31, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 61.1 $ 43.3 $ 37.9 $ 78.6 Long-term 40.5 13.2 23.2 18.7 Total derivatives designated as hedging instruments $ 101.6 $ 56.5 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.1 $ 10.3 $ — $ 1.1 Long-term 0.9 4.9 — 0.9 Total derivatives not designated as hedging instruments $ 3.0 $ 15.2 $ — $ 2.0 Total current position $ 63.2 $ 53.6 $ 37.9 $ 79.7 Total long-term position 41.4 18.1 23.2 19.6 Total derivatives $ 104.6 $ 71.7 $ 61.1 $ 99.3
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 March 31, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 63.2 $ (51.2 ) $ 5.8 $ 39.6 $ (21.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.4 ) - - (2.4 ) 63.2 (53.6 ) 5.8 39.6 (24.2 ) Long Term Position Counterparties with offsetting positions or collateral 41.4 (16.9 ) - 32.7 (8.2 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (1.2 ) - - (1.2 ) 41.4 (18.1 ) - 32.7 (9.4 ) Total Derivatives Counterparties with offsetting positions or collateral 104.6 (68.1 ) 5.8 72.3 (30.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.6 ) - - (3.6 ) $ 104.6 $ (71.7 ) $ 5.8 $ 72.3 $ (33.6 ) Gross Presentation Pro forma net presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 )
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue and Expense	The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Three Months Ended March 31, Hedging Relationships 2018 2017 Commodity contracts $ 64.6 $ 66.2 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended March 31, Location of Gain (Loss) 2018 2017 Revenues $ (26.7 ) $ (6.1 )
Gain (Loss) Recognized in Income on Derivatives	The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended March 31, as Hedging Instruments Derivatives 2018 2017 Commodity contracts Revenue $ (10.8 ) $ (0.8 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2018
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: March 31, 2018 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) $ 104.3 $ 104.3 $ — $ 103.9 $ 0.4 Liabilities from commodity derivative contracts (1) 71.4 71.4 — 67.7 3.7 Permian Acquisition contingent consideration (2) 373.0 373.0 — — 373.0 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 206.7 206.7 — — — TRP Revolver 380.0 380.0 — 380.0 — Senior unsecured notes 4,278.0 4,257.0 — 4,257.0 — Accounts receivable securitization facility 300.0 300.0 — 300.0 — December 31, 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) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — (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 12– 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 – Newly-Formed Joint Ventures and Acquisitions. (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, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of TPL contingent consideration - (0.1 ) Change in fair value of Permian Acquisition contingent consideration (1) - (56.0 ) New Level 3 derivative instruments (0.1 ) - Settlements included in Revenue (0.4 ) - Unrealized gain/(loss) included in OCI 0.9 - Balance, March 31, 2018 $ (3.4 ) $ (375.5 ) (1) Represents the change in fair value between December 31, 2017 and March 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures and Acquisitions for discussion of the initial fair value.

Related Party Transactions - 39

Related Party Transactions - Targa (Tables)	3 Months Ended
	Mar. 31, 2018
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 March 31, 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 59.5 $ 47.0 Targa allocation of general and administrative expense 47.3 42.0 Cash distributions to Targa based on general partner and limited partner ownership 225.7 195.3 Cash contributions from Targa related to limited partner ownership (1) 58.8 641.9 Cash contributions from Targa to maintain its 2% general partner ownership 1.2 13.1 _______________________ (1) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 11 – Partnership Units and Related Matters.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Summary of Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations	The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated . These contracts are comprised primarily of fractionation, export, terminaling and storage agreements. 2018 2019 2020 and after Fixed consideration to be recognized as of March 31, 2018 $ 322.1 $ 368.1 $ 1,400.0

Other Operating (Income) Expe41

Other Operating (Income) Expense (Tables)	3 Months Ended
	Mar. 31, 2018
Other Income And Expenses [Abstract]
Other Operating (Income) Expense	Other operating (income) expense is comprised of the following: Three Months Ended March 31, 2018 2017 (Gain) loss on sale or disposal of assets (1) $ (0.1 ) $ 16.1 Miscellaneous business tax 0.3 0.1 Other 0.1 — $ 0.3 $ 16.2 _________________ _________ (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 Inform42

Supplemental Cash Flow Information (Tables)	3 Months Ended
	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Three Months Ended March 31, 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 39.4 $ 53.5 Income taxes paid, net of refunds 0.2 (0.1 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 1.7 $ 8.3 Impact of capital expenditure accruals on property, plant and equipment (22.3 ) 30.0 Transfers from materials and supplies inventory to property, plant and equipment 0.4 0.4 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 2.1 1.7 Non-cash financing activities: Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures and Acquisitions): Contingent consideration recorded at the acquisition date $ — $ 461.6 Purchase consideration payable recorded for the Permian Acquisition — 90.0 Non-cash balance sheet movements related to acquisition of related party: Intercompany payable 1.4 — Noncontrolling interest 1.2 — __________________ (1) Interest capitalized on major projects was $9.6 million and $1.7 million for the three months ended March 31, 2018 and 2017.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Information by Segment	Reportable segment information is shown in the following tables: Three Months Ended March 31, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 265.2 $ 1,926.3 $ (17.8 ) $ — $ 2,173.7 Fees from midstream services 161.3 120.6 — — 281.9 426.5 2,046.9 (17.8 ) — 2,455.6 Intersegment revenues Sales of commodities 866.5 55.7 — (922.2 ) — Fees from midstream services 1.9 6.9 — (8.8 ) — 868.4 62.6 — (931.0 ) — Revenues $ 1,294.9 $ 2,109.5 $ (17.8 ) $ (931.0 ) $ 2,455.6 Operating margin $ 220.8 $ 138.4 $ (17.8 ) $ — $ 341.4 Other financial information: Total assets (1) $ 10,908.5 $ 3,595.1 $ 103.0 $ 121.1 $ 14,727.7 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 273.2 $ 251.0 $ — $ 33.8 $ 558.0 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Three Months Ended March 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 166.7 $ 1,692.4 $ (1.0 ) $ — $ 1,858.1 Fees from midstream services 118.2 136.3 — — 254.5 284.9 1,828.7 (1.0 ) — 2,112.6 Intersegment revenues Sales of commodities 713.0 75.4 — (788.4 ) — Fees from midstream services 1.9 7.0 — (8.9 ) — 714.9 82.4 — (797.3 ) — Revenues $ 999.8 $ 1,911.1 $ (1.0 ) $ (797.3 ) $ 2,112.6 Operating margin $ 177.4 $ 130.1 $ (1.0 ) $ — $ 306.5 Other financial information: Total assets (1) $ 10,780.4 $ 2,687.2 $ 44.8 $ 57.4 $ 13,569.8 Goodwill $ 369.0 $ — $ — $ — $ 369.0 Capital expenditures $ 139.2 $ 34.6 $ — $ 0.8 $ 174.6 ____________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
Revenues by Product and Service	The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 470.1 $ 481.7 NGL 1,607.3 1,319.7 Condensate 86.9 43.6 Petroleum products 48.2 19.8 2,212.5 1,864.8 Non-customer revenue: Derivative activities - Hedge (28.0 ) (5.9 ) Derivative activities - Non-hedge (1) (10.8 ) (0.8 ) (38.8 ) (6.7 ) Total sales of commodities 2,173.7 1,858.1 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 31.1 31.0 Storage, terminaling, transportation and export 88.7 99.7 Gathering and processing 152.1 107.7 Other 10.0 16.1 Total fees from midstream services 281.9 254.5 Total revenues $ 2,455.6 $ 2,112.6
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 March 31, 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 220.8 $ 177.4 Logistics and Marketing operating margin 138.4 130.1 Other operating margin (17.8 ) (1.0 ) Depreciation and amortization expenses (198.1 ) (191.1 ) General and administrative expenses (52.6 ) (45.5 ) Interest income (expense), net 20.2 (58.6 ) Other, net (54.9 ) (37.3 ) Income (loss) before income taxes $ 56.0 $ (26.0 )

Organization and Operations (De

Organization and Operations (Details) - Series A Cumulative Redeemable Perpetual Preferred Units [Member] - shares	1 Months Ended	3 Months Ended
	Oct. 31, 2015	Mar. 31, 2018	Dec. 31, 2017
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items]
Preferred units, outstanding		5,000,000	5,000,000
Preferred units dividend percentage	9.00%	9.00%

Significant Accounting Polici45

Significant Accounting Policies - Summary of Effect of Adoption on Our Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Sales of commodities	$ 2,173.7	$ 1,858.1
Fees from midstream services	281.9	254.5
Total revenues	2,455.6	2,112.6
Costs and expenses:
Product purchases	1,941	1,654.2
Income from operations	90.4	53.7
Income (loss) before income taxes	56	(26)
Net income (loss)	56	$ (21.3)
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Revenues:
Sales of commodities	2,173.7
Fees from midstream services	281.9
Total revenues	2,455.6
Costs and expenses:
Product purchases	1,941
Income from operations	90.4
Income (loss) before income taxes	56
Net income (loss)	56
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member]
Revenues:
Sales of commodities	2,260.1
Fees from midstream services	288.4
Total revenues	2,548.5
Costs and expenses:
Product purchases	2,033.9
Income from operations	90.4
Income (loss) before income taxes	56
Net income (loss)	56
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member]
Revenues:
Sales of commodities	(86.4)
Fees from midstream services	(6.5)
Total revenues	(92.9)
Costs and expenses:
Product purchases	$ (92.9)

Significant Accounting Polici46

Significant Accounting Policies (Details) - USD ($)	Jan. 01, 2018	Mar. 31, 2018
Minimum [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Payment of commodities due period		10 days
Maximum [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Payment of commodities due period		30 days
Accounting Standards Update 2017-12 [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Effect on retained earnings	$ 0
Derivative hedge accumulated ineffectiveness	$ 0

Newly-Formed Joint Ventures a47

Newly-Formed Joint Ventures and Acquisitions - Additional Information Joint Ventures (Details) $ in Millions	Jan. 01, 2020USD ($)	Feb. 06, 2018MBbls / dJointVenture	Mar. 31, 2018USD ($)	Jan. 31, 2018MMcf / d	Jul. 31, 2017USD ($)mi	May 31, 2017MBbls / d	Dec. 31, 2017USD ($)Bcf	Sep. 30, 2017
Business Acquisition [Line Items]
Fractionation-related infrastructure funded and owned percentage		100.00%
Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | Scenario Forecast [Member]
Business Acquisition [Line Items]
Option to acquire interest, minimum capital increments	$ 100
Option to acquire, percentage of single final purchase	50.00%
Hess Midstream Partners L P | LM4 Plant [Member]
Business Acquisition [Line Items]
Ownership interest				50.00%
Processing capacity | MMcf / d				200
Stonepeak Infrastructure Partners [Member] | GCX DevCo JV [Member]
Business Acquisition [Line Items]
Number of development joint ventures | JointVenture		3
Ownership interest		80.00%
Stonepeak Infrastructure Partners [Member] | Train 6 DevCo JV [Member]
Business Acquisition [Line Items]
Ownership interest		80.00%
Stonepeak Infrastructure Partners [Member] | Grand Prix DevCo JV [Member]
Business Acquisition [Line Items]
Ownership interest		95.00%
GCX DevCo JV [Member] | GCX [Member]
Business Acquisition [Line Items]
Ownership interest		25.00%
Grand Prix DevCo JV [Member] | Grand Prix Joint Venture [Member]
Business Acquisition [Line Items]
Ownership interest		20.00%
Mont Belvieu, Texas [Member] | Train 6 [Member]
Business Acquisition [Line Items]
Capacity of pipeline | MBbls / d		100
Mont Belvieu, Texas [Member] | Train 6 DevCo JV [Member] | Train 6 [Member]
Business Acquisition [Line Items]
Ownership interest in assets		100.00%
Grand Prix Joint Venture [Member]
Business Acquisition [Line Items]
Expected cost of joint venture			$ 1,700
Grand Prix Joint Venture [Member] | Southern Oklahoma [Member]
Business Acquisition [Line Items]
Expected cost of joint venture			$ 350
Grand Prix Joint Venture [Member] | Blackstone Energy Partners [Member]
Business Acquisition [Line Items]
Percentage of joint venture interest sold								25.00%
Grand Prix Joint Venture [Member] | Permian Basin [Member]
Business Acquisition [Line Items]
Capacity of pipeline | MBbls / d						300
Cayenne Joint Venture [Member]
Business Acquisition [Line Items]
Conversion of existing mile gas pipeline | mi					62
Percentage of ownership interest aquired					50.00%
Amount of business aquired					$ 5
Project commencement date					2017-12
Ownership interest			50.00%
GCX [Member]
Business Acquisition [Line Items]
Ownership interest							25.00%
Natural gas transportation cost expected							$ 1,750
GCX [Member] | DCP [Member]
Business Acquisition [Line Items]
Ownership interest							25.00%
GCX [Member] | KMTP [Member]
Business Acquisition [Line Items]
Ownership interest							50.00%
Maximum [Member]
Business Acquisition [Line Items]
Ownership interest			100.00%
Maximum [Member] | Apache Corporation [Member]
Business Acquisition [Line Items]
Percentage of option to purchase equity stake							15.00%
Maximum [Member] | Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | Scenario Forecast [Member]
Business Acquisition [Line Items]
Percentage of option to purchase equity stake	50.00%
Maximum [Member] | Grand Prix Joint Venture [Member] | Permian Basin [Member]
Business Acquisition [Line Items]
Capacity of pipeline | MBbls / d						550
Maximum [Member] | GCX [Member]
Business Acquisition [Line Items]
Capacity of natural gas transported per day | Bcf							1.98

Newly-Formed Joint Ventures a48

Newly-Formed Joint Ventures and Acquisitions - Additional Information Acquisitions (Details) - Permian Acquisition [Member] - USD ($)	May 30, 2017	Mar. 02, 2017	Mar. 31, 2017	Mar. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Cash payments related to acquisition		$ 484,100,000
Additional cash payments related to purchase consideration	$ 90,000,000		$ 90,000,000
Additional cash that has been paid based on potential earn-out payment				$ 373,000,000	$ 317,000,000
Pro forma consolidated results of operations [Abstract]
Acquisition-related costs			$ 5,100,000
Maximum [Member]
Business Acquisition [Line Items]
Additional cash that has been paid based on potential earn-out payment		$ 935,000,000
Targa Resources Corp. [Member]
Business Acquisition [Line Items]
Percentage of ownership interest aquired		100.00%

Newly-Formed Joint Ventures a49

Newly-Formed Joint Ventures and Acquisitions - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Pro forma consolidated results of operations [Abstract]
Revenues	$ 2,126.7
Net income (loss)	$ (23.4)

Newly-Formed Joint Ventures a50

Newly-Formed Joint Ventures and Acquisitions - Additional Information Contingent Liability (Details) - USD ($)	3 Months Ended		10 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Mar. 02, 2017
Business Acquisition [Line Items]
Change in contingent considerations included in Other expense (income)	$ 56,100,000	$ 3,300,000
Permian Acquisition [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment	373,000,000		$ 317,000,000
Potential earn-out payments acquisition date fair value		461,600,000
Change in contingent considerations included in Other expense (income)	56,000,000	$ 3,200,000	(99,300,000)
Earn-out payment	0		$ 6,800,000
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	416,300,000			$ 416,300,000
Second potential earn-out payments acquisition date fair value	$ 373,000,000

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Commodities	$ 79.6	$ 191.6
Materials and supplies	17.1	12.9
Total inventory	$ 96.7	$ 204.5

Property, Plant and Equipment52

Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 14,762	$ 14,198.6
Accumulated depreciation	(3,920.4)	(3,768.7)
Property, plant and equipment, net	10,841.6	10,429.9
Intangible assets	2,736.6	2,736.6
Accumulated amortization	(616.5)	(570.8)
Intangible assets, net	$ 2,120.1	2,165.8
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	$ 7,154.4	7,037.2
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	$ 3,678.3	3,563
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	$ 1,252.3	1,244.1
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	$ 343.6	343.6
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	$ 312.1	303.5
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	$ 144.3	125.7
Construction in Progress [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 1,877	$ 1,581.5

Property, Plant and Equipment53

Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Estimated amortization expense for intangible assets [Abstract]
2,018	$ 182.6
2,019	171.6
2,020	159.4
2,021	149.5
2,022	$ 141.2
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

Property, Plant and Equipment54

Property, Plant and Equipment and Intangible Assets, Schedule of Changes in Intangible Assets(Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Intangible Assets, net [Roll Forward]
Balance at December 31, 2017	$ 2,165.8
Amortization	(45.7)
Balance at March 31, 2018	$ 2,120.1

Property, Plant and Equipment55

Property, Plant and Equipment and Intangible Assets - Additional Information (Details) $ in Millions	May 01, 2018USD ($)
Subsequent Event [Member]
Property Plant And Equipment [Line Items]
Proceeds from sale of property	$ 69.3

Investments in Unconsolidated56

Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)JointVenture
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	38.80%
T2 Joint Ventures [Member]
Schedule Of Equity Method Investments [Line Items]
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture	3
Unamortized excess fair value | $	$ 25.8
Preliminary estimated useful lives of the underlying assets	20 years
T2 La Salle [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	75.00%
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	50.00%
T2 EF Cogen [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	50.00%
Cayenne Joint Venture [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	50.00%
GCX [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	25.00%
Little Missouri [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	50.00%

Investments in Unconsolidated57

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		$ 221.6
Equity earnings (loss)		1.5	$ (12.6)
Cash Distributions	[1]	(13.7)
Contributions	[2]	104
Balance at end of period		313.4
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		45.8
Equity earnings (loss)		4.2
Cash Distributions	[1]	(5.7)
Contributions	[2]	0
Balance at end of period		44.3
T2 La Salle [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		54.1
Equity earnings (loss)		(1.3)
Cash Distributions	[1]	0
Contributions	[2]	0.1
Balance at end of period		52.9
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		109.2
Equity earnings (loss)		(2.6)
Cash Distributions	[1]	0
Contributions	[2]	0
Balance at end of period		106.6
T2 EF Cogen [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		3.9
Equity earnings (loss)		(0.4)
Cash Distributions	[1]	0
Contributions	[2]	0
Balance at end of period		3.5
Cayenne Joint Venture [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		8.6
Equity earnings (loss)		1.6
Cash Distributions	[1]	0
Contributions	[2]	2.1
Balance at end of period		12.3
GCX [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		0
Equity earnings (loss)		0
Cash Distributions	[1]	0
Contributions	[2]	69.5
Balance at end of period		69.5
Little Missouri [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		0
Equity earnings (loss)		0
Cash Distributions	[1]	(8)
Contributions	[2]	32.3
Balance at end of period		$ 24.3
[1]	Includes $1.5 million in distributions received from GCF in excess of our share of cumulative earnings for the three months ended March 31, 2018. 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. Also includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures.
[2]	Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4.

Investments in Unconsolidated58

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Schedule Of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate	$ 1.5	$ 0
Contribution of property, plant and equipment to investment in unconsolidated affiliates	16	$ 1
Little Missouri [Member]
Schedule Of Equity Method Investments [Line Items]
Return of capital from unconsolidated affiliate	$ 8

Accounts Payable and Accrued 59

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$ 593	$ 711.9
Other goods and services	254.7	286.9
Interest	63.4	54.1
Income and other taxes	28.3	26.3
Other	28.9	20.6
Accounts payable and accrued liabilities	968.3	1,106.6
Permian Acquisition [Member]
Components of accounts payable and accrued liabilities [Abstract]
Permian Acquisition contingent consideration, estimated current portion	$ 0	$ 6.8

Accounts Payable and Accrued 60

Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Outstanding checks	$ 56.6	$ 49.7

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Current:
Accounts receivable securitization facility, due December 2018		$ 300	$ 350
Long-term [Abstract]
Long-term debt		4,629.2	4,268
Long-term debt including unamortized premium (discount)		4,658	4,298
Debt issuance costs, net of amortization		(28.8)	(30)
Total debt obligations		4,929.2	4,618
Irrevocable standby letters of credit outstanding		25.9	27.2
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 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] | Senior Unsecured 5% Notes due January 2028 [Member]
Long-term [Abstract]
Long-term debt		750	750
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		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		48.1	48.1
Unamortized premium		0.4	0.4
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[1]	$ 380	$ 20
[1]	As of March 31, 2018, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,194.1 million.

Debt Obligations (Parenthetical

Debt Obligations (Parenthetical) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Debt Instrument [Line Items]
Maturity date	Oct. 31, 2020	[1]
Maximum borrowing capacity	$ 1,600
Remaining borrowing capacity	$ 1,194.1
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2018 [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 31, 2018
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 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] | Senior Unsecured 5% Notes due January 2028 [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 31, 2028
Interest rate on fixed rate debt	5.00%
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Debt Instrument [Line Items]
Maturity date	Nov. 30, 2021
Interest rate on fixed rate debt	4.75%
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 31, 2023
Interest rate on fixed rate debt	5.875%
[1]	As of March 31, 2018, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,194.1 million.

Debt Obligations, Interest Rate

Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details)	Mar. 31, 2018
Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred	2.60%
Minimum [Member] | Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	2.60%
Maximum [Member] | Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	2.90%
TRP Revolver [Member]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred	3.80%
TRP Revolver [Member] | Minimum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	3.40%
TRP Revolver [Member] | Maximum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	5.50%

Debt Obligations - Additional I

Debt Obligations - Additional Information (Details) - Subsequent Event [Member] - Senior Unsecured Notes [Member] - Senior Unsecured 5⅞% Notes due April 2026 [Member] $ in Millions	1 Months Ended
	Apr. 30, 2018USD ($)
Debt Instrument [Line Items]
Senior notes issued	$ 1,000
Interest rate on fixed rate debt	5.875%
Maturity date	Apr. 30, 2026
Net proceeds from senior notes	$ 992.3

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Other Liabilities Noncurrent [Line Items]
Asset retirement obligations	$ 52.5	$ 50.3
Mandatorily redeemable preferred interests	4.2	76.2
Deferred revenue	135.2	136.2
Other liabilities	3.2	3.1
Total long-term liabilities	568.1	576
Permian Acquisition [Member]
Other Liabilities Noncurrent [Line Items]
Permian Acquisition contingent consideration, noncurrent portion	$ 373	$ 310.2

Other Long-term Liabilities - C

Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	$ 50.3
Change in cash flow estimate	2.1	$ 1.7
Accretion expense	0.9	$ 1.3
Retirement of ARO	(0.8)
Balance at March 31, 2018	$ 52.5

Other Long-term Liabilities, Ma

Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)JointVenture	Mar. 31, 2017USD ($)
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2017	$ 76.2
Increase (decrease) in redemption value of mandatorily redeemable preferred interests	(72.5)	$ 2.5
Balance at March 31, 2018	4.2
Mandatorily Redeemable Preferred Interests [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2017	76.2
Income attributable to mandatorily redeemable preferred interests	0.5
Increase (decrease) in redemption value of mandatorily redeemable preferred interests	(72.5)
Balance at March 31, 2018	$ 4.2
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	3 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 31, 2017USD ($)	Dec. 27, 2015bbl
Deferred Revenue [Abstract]
Deferred Revenue	$ 135.2	$ 136.2
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

Other Long-term Liabilities, Co

Other Long-term Liabilities, Components Of Deferred Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 135.2	$ 136.2
Other Deferred Revenue [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	5.1	5.5
Channelview Splitter [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	86	86
Gas Contract Amendment [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 44.1	$ 44.7

Other Long-term Liabilities, Ch

Other Long-term Liabilities, Changes In Deferred Revenue (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Other Liabilities Noncurrent [Abstract]
Balance at December 31, 2017	$ 136.2
Revenue recognized	(1)
Balance at March 31, 2018	$ 135.2

Other Long-term Liabilities, Pe

Other Long-term Liabilities, Permian Acquisition Contingent Consideration (Details) - USD ($)	3 Months Ended		10 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Mar. 02, 2017
Business Acquisition Contingent Consideration [Line Items]
Increase (decrease) in fair value of contingent consideration liability	$ 56,100,000	$ 3,300,000
Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
Preliminary acquisition date fair value of the contingent consideration		461,600,000
Increase (decrease) in fair value of contingent consideration liability	56,000,000	$ 3,200,000	$ (99,300,000)
Additional cash that may be paid based on potential earn-out payment	373,000,000		$ 317,000,000
Permian Acquisition [Member] | Other Long-term Liabilities [Member]
Business Acquisition Contingent Consideration [Line Items]
Preliminary acquisition date fair value of the contingent consideration	416,300,000			$ 416,300,000
Fair value of second potential earn-out payment	373,000,000
Permian Acquisition [Member] | Accounts Payable and Accrued Liabilities [Member]
Business Acquisition Contingent Consideration [Line Items]
Fair value of first potential earn-out payment	$ 0

Other Long-term Liabilities -72

Other Long-term Liabilities - Schedule of Changes in Permian Acquisition Contingent Consideration (Details) - USD ($) $ in Millions	3 Months Ended		10 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Business Acquisition Contingent Consideration [Line Items]
Increase in fair value due to factors occurring after acquisition date	$ 56.1	$ 3.3
Permian Acquisition [Member]
Business Acquisition Contingent Consideration [Line Items]
Balance at December 31, 2017	317
Increase in fair value due to factors occurring after acquisition date	56	$ 3.2	$ (99.3)
Balance at March 31, 2018	373		317
Less: Current portion	0		(6.8)
Long-term balance at March 31, 2018	$ 373		$ 310.2

Partnership Units and Related73

Partnership Units and Related Matters, Distributions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Distributions declared and/or paid by the Partnership [Abstract]
Date Paid Or to Be Paid	May 11, 2018	Feb. 12, 2018
Total Distributions	$ 228.5		$ 198.1
Distributions Paid [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Total Distributions	229.7	$ 228.5
Distributions to Targa Resources Corp.	$ 226.9	$ 225.7

Partnership Units and Related74

Partnership Units and Related Matters (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended
	Apr. 30, 2018	Oct. 31, 2015	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Limited Partners Capital Account [Line Items]
Contributions from Targa Resources Corp.			$ 60		$ 655
Distributions declared and/or paid by the Partnership [Abstract]
Date Paid Or to Be Paid			May 11, 2018	Feb. 12, 2018
Subsequent Event [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date of declaration for cash distribution	2018-04
Cash distribution declared per unit (in dollars per share)	$ 0.1875
Distributions to Targa Resources Corp.	$ 0.9
Date Paid Or to Be Paid	May 15, 2018
Series A Preferred Limited Partner Units [Member]
Limited Partners Capital Account [Line Items]
Series A preferred limited partners units issued (in units)			5,000,000	5,000,000
Preferred units dividend percentage		9.00%	9.00%
Distribution to holders of preferred units			$ 2.8
Series A Preferred Limited Partner Units [Member] | 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. (in units)			0
Contributions from Targa Resources Corp.			$ 60

Derivative Instruments and He75

Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details)	3 Months Ended
	Mar. 31, 2018MMBTUbbl
Year 2020 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Year 2020 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2020 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	4,567
Year 2020 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	10,417
Year 2020 [Member] | Future | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Year 2020 [Member] | Future | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Year 2020 [Member] | Options [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Year 2020 [Member] | Options [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Year 2018 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	4,990
Year 2018 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	170,739
Year 2018 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	22,779
Year 2018 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	138,009
Year 2018 [Member] | Future | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	5,096
Year 2018 [Member] | Future | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	8,923
Year 2018 [Member] | Options [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	590
Year 2018 [Member] | Options [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	1,310
Year 2019 [Member] | Swaps [Member] | Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	2,653
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	131,506
Year 2019 [Member] | Swaps [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	13,449
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	78,062
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)	1,383
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] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	410

Derivative Instruments and He76

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative assets	$ 104.6	$ 61.1
Derivative assets	63.2	37.9
Derivative assets	41.4	23.2
Derivative liabilities	71.7	99.3
Derivative liabilities	53.6	79.7
Derivative liabilities	18.1	19.6
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	101.6	61.1
Derivative liabilities	56.5	97.3
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	61.1	37.9
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	40.5	23.2
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	43.3	78.6
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	13.2	18.7
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	3	0
Derivative liabilities	15.2	2
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	2.1	0
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0.9	0
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	10.3	1.1
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 4.9	$ 0.9

Derivative Instruments and He77

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Asset [Abstract]
Gross asset	$ 104.6	$ 61.1
Pro forma net presentation, asset, total	72.3	28.6
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	104.6	61.1
Pro forma net presentation, asset	72.3	28.6
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	63.2	37.9
Pro forma net presentation, asset, current	39.6	13.8
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	63.2	37.9
Pro forma net presentation, asset	39.6	13.8
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	41.4	23.2
Pro forma net presentation, asset, noncurrent	32.7	14.8
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	41.4	23.2
Pro forma net presentation, asset	$ 32.7	$ 14.8

Derivative Instruments and He78

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Liability [Abstract]
Gross liability	$ (71.7)	$ (99.3)
Pro forma net presentation, liability, total	(33.6)	(43.9)
Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(68.1)	(92)
Pro forma net presentation, liability, total	(30)	(36.6)
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(3.6)	(7.3)
Pro forma net presentation, liability, total	(3.6)	(7.3)
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	(53.6)	(79.7)
Pro forma net presentation, liability, current	(24.2)	(32.7)
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(51.2)	(74.7)
Pro forma net presentation, liability, current	(21.8)	(27.7)
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(2.4)	(5)
Pro forma net presentation, liability, current	(2.4)	(5)
Long-term Position [Member]
Derivative Liability [Abstract]
Gross liability	(18.1)	(19.6)
Pro forma net presentation, liability, noncurrent	(9.4)	(11.2)
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(16.9)	(17.3)
Pro forma net presentation, liability, noncurrent	(8.2)	(8.9)
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(1.2)	(2.3)
Pro forma net presentation, liability, noncurrent	$ (1.2)	$ (2.3)

Derivative Instruments and He79

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Asset [Abstract]
Gross collateral	$ 5.8	$ 22.9
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	5.8	22.9
Current Position [Member]
Derivative Asset [Abstract]
Gross collateral	5.8	22.9
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	$ 5.8	$ 22.9

Derivative Instruments and He80

Derivative Instruments and Hedging Activities - Additional Information (Details) $ in Millions	Mar. 31, 2018USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Estimated fair value of derivative instruments, net asset	$ 32.9
Amount expected to reclassify commodity hedge related deferred gains to earnings before income taxes	45.2
Amount of deferred gains to be reclassified into earnings before income taxes over next twelve months	$ 17.9

Derivative Instruments and He81

Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from OCI into Income (Effective Portion)	$ (26.7)	$ (6.1)
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives	(10.8)	(0.8)
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ 64.6	$ 66.2

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) $ in Millions	Mar. 31, 2018USD ($)Swap
Fair Value Disclosures [Abstract]
Derivatives financial instruments, fair value, net	$ 32.9
Derivative fair value of net liability if commodity price increases by 10 percent	42.9
Derivative fair value of net asset if commodity price decreases by 10 percent	$ 108.8
Number of natural gas basis swaps categorized as Level 3 | Swap	12

Fair Value Measurements, Breakd

Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts		$ 72.3	$ 28.6
Liabilities from commodity derivative contracts		33.6	43.9
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Accounts receivable securitization facility		300	350
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		373	317
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	104.3	60.3
Liabilities from commodity derivative contracts	[1]	71.4	98.5
Additional cash that may be paid based on potential earn-out payment	[2]		317
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		206.7	124.7
Accounts receivable securitization facility		300	350
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]	373
Carrying Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		380	20
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	2.4
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,278	4,278
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	104.3	60.3
Liabilities from commodity derivative contracts	[1]	71.4	98.5
Additional cash that may be paid based on potential earn-out payment	[2]		317
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		206.7	124.7
Accounts receivable securitization facility		300	350
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]	373
Fair Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		380	20
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	2.4
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,257	4,362.4
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	103.9	58.8
Liabilities from commodity derivative contracts	[1]	67.7	93.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Accounts receivable securitization facility		300	350
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		380	20
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		4,257	4,362.4
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	0.4	1.5
Liabilities from commodity derivative contracts	[1]	3.7	5.2
Additional cash that may be paid based on potential earn-out payment	[2]		317
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]	373
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	$ 2.4
[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 12– 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 – Newly-Formed Joint Ventures and Acquisitions.
[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	3 Months Ended
	Mar. 31, 2018USD ($)
Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period	$ (319.4)
New Level 3 derivative instruments	0
Settlements included in Revenue	0
Unrealized gain/(loss) included in OCI	0
Balance, end of period	(375.5)
Targa Pipeline Partners LP [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(0.1)
Permian Acquisition [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(56)	[1]
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	(3.8)
New Level 3 derivative instruments	(0.1)
Settlements included in Revenue	(0.4)
Unrealized gain/(loss) included in OCI	0.9
Balance, end of period	(3.4)
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	[1]
[1]	Represents the change in fair value between December 31, 2017 and March 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures and Acquisitions for discussion of the initial fair value.

Related Party Transactions - 85

Related Party Transactions - Targa (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Summary of transactions with Targa [Abstract]
Cash distributions to Targa based on general partner and limited partner ownership		$ 228.5	$ 198.1
Cash contributions from Targa related to limited partner ownership		58.8	641.9
Targa Resources Corp. [Member]
Summary of transactions with Targa [Abstract]
Targa billings of payroll and related costs included in operating expenses		59.5	47
Targa allocation of general and administrative expense		47.3	42
Cash distributions to Targa based on general partner and limited partner ownership		225.7	195.3
Cash contributions from Targa related to limited partner ownership	[1]	58.8	641.9
Contributions from Targa Resources Corp		$ 1.2	$ 13.1
Percentage of general partner's interest maintained		2.00%
[1]	The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 11 – Partnership Units and Related Matters.

Related Party Transactions - 86

Related Party Transactions - Targa (Parenthetical) (Details) - Targa Resources Corp. [Member]	3 Months Ended
	Mar. 31, 2018
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%

Related Party Transactions - 87

Related Party Transactions - Targa - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018	Feb. 28, 2018	Jan. 31, 2018	Dec. 31, 2010
Maximum [Member]
Related Party Transaction [Line Items]
Ownership interest	100.00%
SAJET Resources LLC [Member]
Related Party Transaction [Line Items]
Extinguishment of debt in exchange for promissory note	$ 9.9
SAJET Resources LLC [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Minority shareholders interest sold		1.60%
Minority shareholders interest amount		$ 0.1
SAJET Resources LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Amount charged to related parties for service.			$ 0.1	$ 0.1
SAJET Resources LLC [Member] | Current and Former Executives, Managers and Directors [Member]
Related Party Transaction [Line Items]
Collective own interest rate					18.00%
Warburg Funds Transaction [Member]
Related Party Transaction [Line Items]
Percentage of ownership interest aquired	82.00%
Cash payments related to acquisition	$ 5

Revenue - Estimated Minimum Rev

Revenue - Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations (Details) $ in Millions	Mar. 31, 2018USD ($)
Revenue From Contract With Customer [Abstract]
Fixed consideration to be recognized, 2018	$ 322.1
Fixed consideration to be recognized, 2019	368.1
Fixed consideration to be recognized, 2020 and after	$ 1,400

Revenue - Additional Informatio

Revenue - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Minimum [Member]
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Estimated remaining duration of contracts	1 year
Maximum [Member]
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Estimated remaining duration of contracts	25 years

Other Operating (Income) Expe90

Other Operating (Income) Expense (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Other Income And Expenses [Abstract]
(Gain) loss on sale or disposal of assets	[1]	$ (0.1)	$ 16.1
Miscellaneous business tax		0.3	0.1
Other		0.1
Total other operating (income) expense		$ 0.3	$ 16.2
[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) Expe91

Other Operating (Income) Expense (Parenthetical) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Other Operating Income Expense [Line Items]
Loss on sale or disposal of assets	[1]	$ 0.1	$ (16.1)
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 Inform92

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		May 30, 2017	Mar. 31, 2018	Mar. 31, 2017
Cash [Abstract]
Interest paid, net of capitalized interest	[1]		$ 39.4	$ 53.5
Income taxes paid, net of refunds			0.2	(0.1)
Non-cash investing activities [Abstract]
Deadstock commodity inventory transferred to property, plant and equipment			1.7	8.3
Impact of capital expenditure accruals on property, plant and equipment			(22.3)	30
Transfers from materials and supplies inventory to property, plant and equipment			0.4	0.4
Contribution of property, plant and equipment to investments in unconsolidated affiliates			16	1
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			2.1	1.7
Non-cash balance sheet movements related to acquisition of related party:
Intercompany payable			1.4
Noncontrolling interest			$ 1.2
Permian Acquisition [Member]
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures and Acquisitions):
Contingent consideration recorded at the acquisition date				461.6
Purchase consideration payable recorded for the Permian Acquisition		$ 90		$ 90
[1]	Interest capitalized on major projects was $9.6 million and $1.7 million for the three months ended March 31, 2018 and 2017.

Supplemental Cash Flow Inform93

Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Interest capitalized on major projects	$ 9.6	$ 1.7

Segment Information, Revenues a

Segment Information, Revenues and Operating Margin (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)Segment	Mar. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	2
Revenues [Abstract]
Sales of commodities	$ 2,173.7	$ 1,858.1
Fees from midstream services	281.9	254.5
Revenues	2,455.6	2,112.6
Operating margin	341.4	306.5
Gathering and Processing [Member]
Revenues [Abstract]
Revenues	1,294.9	999.8
Operating margin	220.8	177.4
Logistics and Marketing [Member]
Revenues [Abstract]
Revenues	2,109.5	1,911.1
Operating margin	138.4	130.1
Other [Member]
Revenues [Abstract]
Revenues	(17.8)	(1)
Operating margin	(17.8)	(1)
Corporate and Elimination [Member]
Revenues [Abstract]
Revenues	(931)	(797.3)
Operating Segments [Member]
Revenues [Abstract]
Sales of commodities	2,173.7	1,858.1
Fees from midstream services	281.9	254.5
Revenues	2,455.6	2,112.6
Operating Segments [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	265.2	166.7
Fees from midstream services	161.3	118.2
Revenues	426.5	284.9
Operating Segments [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	1,926.3	1,692.4
Fees from midstream services	120.6	136.3
Revenues	2,046.9	1,828.7
Operating Segments [Member] | Other [Member]
Revenues [Abstract]
Sales of commodities	(17.8)	(1)
Revenues	(17.8)	(1)
Intersegment Eliminations [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	866.5	713
Fees from midstream services	1.9	1.9
Revenues	868.4	714.9
Intersegment Eliminations [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	55.7	75.4
Fees from midstream services	6.9	7
Revenues	62.6	82.4
Intersegment Eliminations [Member] | Corporate and Elimination [Member]
Revenues [Abstract]
Sales of commodities	(922.2)	(788.4)
Fees from midstream services	(8.8)	(8.9)
Revenues	$ (931)	$ (797.3)

Segment Information, Other Fina

Segment Information, Other Financial Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Mar. 02, 2017
Other financial information [Abstract]
Total assets		$ 14,727.7		$ 14,359
Goodwill		256.6		$ 256.6
Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	14,727.7			$ 13,569.8
Goodwill		256.6			369
Capital expenditures		558	$ 174.6
Gathering and Processing [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	10,908.5			10,780.4
Goodwill		256.6			369
Capital expenditures		273.2	139.2
Logistics and Marketing [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	3,595.1			2,687.2
Capital expenditures		251	34.6
Other [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	103			44.8
Corporate and Elimination [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	121.1			$ 57.4
Capital expenditures		$ 33.8	$ 0.8
[1]	Assets in the Corporate and Eliminations column 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
		Mar. 31, 2018	Mar. 31, 2017
Revenue from External Customer [Line Items]
Sales of commodities		$ 2,173.7	$ 1,858.1
Non-customer revenue		(38.8)	(6.7)
Fees from midstream services		281.9	254.5
Total revenues		2,455.6	2,112.6
Designated as Hedging Instrument [Member]
Revenue from External Customer [Line Items]
Non-customer revenue		(28)	(5.9)
Not Designated as Hedging Instrument [Member]
Revenue from External Customer [Line Items]
Non-customer revenue	[1]	(10.8)	(0.8)
Revenue Recognized from Contracts with Customers [Member]
Revenue from External Customer [Line Items]
Sales of commodities		2,212.5	1,864.8
Revenue Recognized from Contracts with Customers [Member] | Natural Gas [Member]
Revenue from External Customer [Line Items]
Sales of commodities		470.1	481.7
Revenue Recognized from Contracts with Customers [Member] | NGL [Member]
Revenue from External Customer [Line Items]
Sales of commodities		1,607.3	1,319.7
Revenue Recognized from Contracts with Customers [Member] | Condensate [Member]
Revenue from External Customer [Line Items]
Sales of commodities		86.9	43.6
Revenue Recognized from Contracts with Customers [Member] | Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sales of commodities		48.2	19.8
Revenue Recognized from Contracts with Customers [Member] | Fractionating and Treating [Member]
Revenue from External Customer [Line Items]
Fees from midstream services		31.1	31
Revenue Recognized from Contracts with Customers [Member] | Storage, Terminaling, Transportation and Export [Member]
Revenue from External Customer [Line Items]
Fees from midstream services		88.7	99.7
Revenue Recognized from Contracts with Customers [Member] | Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Fees from midstream services		152.1	107.7
Revenue Recognized from Contracts with Customers [Member] | Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services		$ 10	$ 16.1
[1]	Represents derivative activities that are not designated as hedging instruments under ASC 815.

Segment Information, Reconcilia

Segment Information, Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	$ 341.4	$ 306.5
Depreciation and amortization expenses	(198.1)	(191.1)
General and administrative expenses	(52.6)	(45.5)
Interest income (expense), net	20.2	(58.6)
Other, net	(54.9)	(37.3)
Income (loss) before income taxes	56	(26)
Gathering and Processing [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	220.8	177.4
Logistics and Marketing [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	138.4	130.1
Other [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	$ (17.8)	$ (1)