10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	65-1295427
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1000 Louisiana St, Suite 4300, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐		Accelerated filer	☐
Non-accelerated filer	☑	(Do not check if a smaller reporting company)	Smaller reporting company	☐
			Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑.

As of May 1, 2017, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	4
Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016	5
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016	6
Consolidated Statements of Changes in Owners' Equity for the three months ended March 31, 2017	7
Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016	8
Notes to Consolidated Financial Statements	9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3. Quantitative and Qualitative Disclosures About Market Risk	49
Item 4. Controls and Procedures	54
PART II—OTHER INFORMATION
Item 1. Legal Proceedings	55
Item 1A. Risk Factors	55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3. Defaults Upon Senior Securities	55
Item 4. Mine Safety Disclosures	55
Item 5. Other Information	55
Item 6. Exhibits	56
SIGNATURES
Signatures	58

1

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or “the Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

• the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services;

• the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation services and markets;

• our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations;

• the amount of collateral required to be posted from time to time in our transactions;

• our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;

• the level of creditworthiness of counterparties to various transactions with us;

• changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

• weather and other natural phenomena;

• industry changes, including the impact of consolidations and changes in competition;

• our ability to obtain necessary licenses, permits and other approvals;

• our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;

• general economic, market and business conditions; and

• the risks described in our Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II- Other Information, Item 1A. Risk Factors.” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

2

As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

Bbl	Barrels (equal to 42 U.S. gallons)
BBtu	Billion British thermal units
Bcf	Billion cubic feet
Btu	British thermal units, a measure of heating value
/d	Per day
GAAP	Accounting principles generally accepted in the United States of America
gal	U.S. gallons
GPM	Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas
LACT	Lease Automatic Custody Transfer
LIBOR	London Interbank Offered Rate
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMgal	Million U.S. gallons
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
Price Index Definitions
C2-OPIS-MB	Ethane, Oil Price Information Service, Mont Belvieu, Texas
C3-OPIS-MB	Propane, Oil Price Information Service, Mont Belvieu, Texas
C5-OPIS-MB	Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas
EP-PERMIAN	Inside FERC Gas Market Report, El Paso (Permian Basin)
IC4-OPIS-MB	Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas
IF-PB	Inside FERC Gas Market Report, Permian Basin
IF-PEPL	Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint
IF-WAHA	Inside FERC Gas Market Report, West Texas WAHA
NC4-OPIS-MB	Normal Butane, Oil Price Information Service, Mont Belvieu, Texas
NG-NYMEX	NYMEX, Natural Gas
WTI-NYMEX	NYMEX, West Texas Intermediate Crude Oil

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

					March 31,			December 31,
					2017			2016
					(Unaudited)
					(In millions)
ASSETS
Current assets:
Cash and cash equivalents					$	71.7		$	68.0
Trade receivables, net of allowances of $0.1 and $0.9 million at March 31, 2017 and December 31, 2016						536.1			673.2
Inventories						75.5			137.7
Assets from risk management activities						23.9			16.8
Other current assets						26.9			31.5
Total current assets						734.1			927.2
Property, plant and equipment						12,950.2			12,511.9
Accumulated depreciation						(2,986.8	)		(2,821.0	)
Property, plant and equipment, net						9,963.4			9,690.9
Intangible assets, net						2,238.8			1,654.0
Goodwill, net						369.0			210.0
Long-term assets from risk management activities						21.6			5.1
Investments in unconsolidated affiliates						227.0			240.8
Other long-term assets						15.9			16.9
Total assets					$	13,569.8		$	12,744.9
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities					$	819.5		$	773.9
Accounts payable to Targa Resources Corp.						46.5			61.0
Liabilities from risk management activities						22.2			49.1
Current maturities of debt						534.9			275.0
Total current liabilities						1,423.1			1,159.0
Long-term debt						3,778.3			4,177.0
Long-term liabilities from risk management activities						7.9			26.1
Deferred income taxes, net						26.4			26.9
Other long-term liabilities						676.4			205.3
Contingencies (see Note 16)
Owners' equity:
Series A preferred limited partners	Issued		Outstanding			120.6			120.6
March 31, 2017		5,000,000		5,000,000
December 31, 2016		5,000,000		5,000,000
Common limited partners	Issued		Outstanding			6,360.9			5,939.9
March 31, 2017		275,168,410		275,168,410
December 31, 2016		275,168,410		275,168,410
General partner	Issued		Outstanding			805.3			796.7
March 31, 2017		5,629,136		5,629,136
December 31, 2016		5,629,136		5,629,136
Accumulated other comprehensive income (loss)						10.5			(61.8	)
						7,297.3			6,795.4
Noncontrolling interests in subsidiaries						360.4			355.2
Total owners' equity						7,657.7			7,150.6
Total liabilities and owners' equity					$	13,569.8		$	12,744.9
See notes to consolidated financial statements.

4

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,
	2017			2016
	(Unaudited)
	(In millions)
Revenues:
Sales of commodities	$	1,858.1		$	1,171.0
Fees from midstream services		254.5			271.4
Total revenues		2,112.6			1,442.4
Costs and expenses:
Product purchases		1,654.2			1,011.0
Operating expenses		151.9			132.0
Depreciation and amortization expense		191.1			193.5
General and administrative expense		45.5			43.4
Goodwill impairment		—			24.0
Other operating (income) expense		16.2			1.0
Income from operations		53.7			37.5
Other income (expense):
Interest expense, net		(58.6	)		(46.9	)
Equity earnings (loss)		(12.6	)		(4.8	)
Gain from financing activities		—			24.7
Other		(8.5	)		(0.1	)
Income (loss) before income taxes		(26.0	)		10.4
Income tax (expense) benefit		4.7			0.2
Net income (loss)		(21.3	)		10.6
Less: Net income attributable to noncontrolling interests		6.0			3.0
Net income (loss) attributable to Targa Resources Partners LP	$	(27.3	)	$	7.6
Net income attributable to preferred limited partners	$	2.8		$	2.8
Net income (loss) attributable to general partner		(0.6	)		14.7
Net income (loss) attributable to common limited partners		(29.5	)		(9.9	)
Net income (loss) attributable to Targa Resources Partners LP	$	(27.3	)	$	7.6

See notes to consolidated financial statements.

5

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended March 31,
	2017			2016
	(Unaudited)
	(In millions)
Net income (loss)	$	(21.3	)	$	10.6
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		66.2			6.7
Settlements reclassified to revenues		6.1			(24.2	)
Other comprehensive income (loss)		72.3			(17.5	)
Comprehensive income (loss)		51.0			(6.9	)
Less: Comprehensive income attributable to noncontrolling interests		6.0			3.0
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	45.0		$	(9.9	)

See notes to consolidated financial statements.

6

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

																Accumulated
	Limited					Limited					General					Other			Treasury				Non-
	Partner					Partner					Partner					Comprehensive			Units				controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Units		Amount		Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance December 31, 2016		5,000	$	120.6			275,168	$	5,939.9			5,629	$	796.7		$	(61.8	)		—	$	—	$	355.2		$	7,150.6
Contributions from Targa    Resources Corp.		—		—			—		641.9			—		13.1			—			—		—		—			655.0
Distributions to noncontrolling    interests		—		—			—		—			—		—			—			—		—		(9.7	)		(9.7	)
Contributions from noncontrolling    interests		—		—			—		—			—		—			—			—		—		8.9			8.9
Other comprehensive income   (loss)		—		—			—		—			—		—			72.3			—		—		—			72.3
Net income (loss)		—	2.8				—		(29.5	)		—		(0.6	)		—			—		—		6.0			(21.3	)
Distributions		—		(2.8	)		—		(191.4	)		—		(3.9	)		—			—		—		—			(198.1	)
Balance March 31, 2017		5,000	$	120.6			275,168	$	6,360.9			5,629	$	805.3		$	10.5			—	$	—	$	360.4		$	7,657.7

																	Accumulated
	Limited					Limited						General					Other			Treasury							Non-
	Partner					Partner						Partner					Comprehensive				Units						controlling
	Preferred		Amount			Common			Amount			Units		Amount			Income (Loss)				Units			Amount			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance December 31, 2015		5,000	$	120.6			184,871		$	4,550.4			3,773	$	1,735.3		$	86.8				212		$	(10.3	)	$	420.1		$	6,902.9
Compensation on equity grants		—		—			—			2.2			—		—			—				—			—			—			2.2
Distribution equivalent rights		—		—			—			(0.2	)		—		—			—				—			—			—			(0.2	)
Issuance of common units under compensation program		—		—			30			—			—		—			—				—			—			—			—
Units tendered for tax    withholding obligations		—		—			(1	)		—			—		—			—				1			(0.1	)		—			(0.1	)
Cancellation of treasury units		—		—			-			(10.2	)		—		(0.2	)		—				(213	)		10.4			—			—
Contributions from Targa    Resources Corp.		—		—			45,103			785.0			921		16.0			—				—			—			—			801.0
Distributions to    noncontrolling interests		—		—			—			—			—		—			—				—			—			(2.1	)		(2.1	)
Contributions from noncontrolling interests		—		—			—			—			—		—			—				—			—			6.0			6.0
Other comprehensive    income (loss)		—		—			—			—			—		—			(17.5	)			—			—			—			(17.5	)
Net income		—		2.8			—			(9.9	)		—		14.7			—				—			—			3.0			10.6
Distributions		—		(2.8	)		—			(152.5	)		—		(47.9	)		—				—			—			—			(203.2	)
Balance March 31, 2016		5,000	$	120.6			230,003		$	5,164.8			4,694	$	1,717.9		$	69.3				—		$	—		$	427.0		$	7,499.6

See notes to consolidated financial statements.

7

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Three Months Ended March 31,
		2017			2016
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)		$	(21.3	)	$	10.6
Adjustments to reconcile net income (loss) to net cash    provided by operating activities:
Amortization in interest expense			2.4			3.4
Compensation on equity grants			—			2.2
Depreciation and amortization expense			191.1			193.5
Goodwill impairment			—			24.0
Accretion of asset retirement obligations			1.3			1.1
Increase (decrease) in redemption value of mandatorily redeemable preferred interests			2.5			(18.5	)
Deferred income tax expense (benefit)			(0.5	)		(6.6	)
Equity (earnings) loss of unconsolidated affiliates			12.6			4.8
Distributions of earnings received from unconsolidated affiliates			2.7			—
Risk management activities			8.5			4.4
(Gain) loss on sale or disposition of assets			16.1			0.9
(Gain) loss from financing activities			—			(24.7	)
Change in contingent considerations			3.3			—
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets			140.6			99.3
Inventories			53.7			62.1
Accounts payable and other liabilities			(99.8	)		(114.5	)
Net cash provided by operating activities			313.2			242.0
Cash flows from investing activities
Outlays for property, plant and equipment			(144.2	)		(190.1	)
Outlays for business acquisition, net of cash acquired			(480.8	)		—
Investments in unconsolidated affiliates			(0.5	)		—
Return of capital from unconsolidated affiliates			—			3.4
Other, net			—			(1.3	)
Net cash used in investing activities			(625.5	)		(188.0	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facility			480.0			425.0
Repayments of credit facility			(630.0	)		(705.0	)
Proceeds from borrowings under accounts receivable securitization facility			75.0			5.7
Repayments of accounts receivable securitization facility			(65.0	)		(75.0	)
Redemption of senior notes			—			(330.6	)
Costs incurred in connection with financing arrangements			(0.1	)		(7.5	)
Repurchase of common units under compensation plans			—			(0.1	)
Contributions from general partner			13.1			16.0
Contributions from TRC			641.9			785.0
Contributions from noncontrolling interests			8.9			6.0
Distributions to noncontrolling interests			(9.7	)		(2.1	)
Distributions to unitholders			(198.1	)		(203.2	)
Payments of distribution equivalent rights			—			(0.3	)
Net cash provided by (used in) financing activities			316.0			(86.1	)
Net change in cash and cash equivalents			3.7			(32.1	)
Cash and cash equivalents, beginning of period			68.0			135.4
Cash and cash equivalents, end of period		$	71.7		$	103.3

See notes to consolidated financial statements.

8

TARGA RESOURCES PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1 — Organization and Operations

Our Organization

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transactions, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

Our Operations

We are engaged in the business of:

• gathering, compressing, treating, processing and selling natural gas;

• storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;

• gathering, storing and terminaling 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.

9

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

The unaudited consolidated financial statements for the three months ended March 31, 2017 and 2016 include all adjustments that we believe are necessary for a fair statement of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

Our financial results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year.

Note 3 — Significant Accounting Policies

Accounting Policy Updates

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. There were no significant updates or revisions to our policies during the three months ended March 31, 2017, except as noted below.

Recent Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

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In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

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). These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Recognition of Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset

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transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We are currently evaluating the effects of such amendments.

Goodwill Impairment

In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary.

Other Income

In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. The amendment also impacts the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendment on our consolidated financial statements. 

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Note 4 – Business Acquisitions and Divestitures

2017 Acquisition

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 will pay $90.0 million within 90 days of closing (collectively, the “initial purchase price”). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.

New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.

New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017 and we expect that New Midland’s gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

The acquired businesses contributed revenues of $8.1 million and a net loss of $2.6 million to us for the period from March 1, 2017 to March 31, 2017, and are reported in our Gathering and Processing segment. As of March 31, 2017, we had incurred $5.1 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the three months ended March 31, 2017.

Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations

The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

	March 31, 2017			March 31, 2016
	Pro Forma			Pro Forma
Revenues	$	2,126.7		$	1,445.0
Net income (loss)		(22.7	)		(7.5	)

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:

• Reflect the amortization expense resulting from the preliminary estimate of the fair value of intangible assets recognized as part of the Permian Acquisition. For the purposes of preparing the pro forma adjustments we have assumed a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations.

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• Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the preliminary estimate of the fair value of property, plant and equipment acquired.

• Exclude $5.1 million of acquisition-related costs incurred as of March 31, 2017 from pro forma net income for the three months ended March 31, 2017. Pro forma net income for the three months ended March 31, 2016 was adjusted to include those charges.

The following table summarizes the consideration transferred to acquire New Delaware and New Midland:

Fair Value of Consideration Transferred:
Cash paid, net of cash acquired (1)	$	480.8
Purchase consideration payable (2)		90.0
Contingent consideration		461.6
Total	$	1,032.4

(1) Net of cash acquired of $3.3 million.

(2) The payable will be settled in cash within 90 days from March 1, 2017.

We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the completion of the valuation and other post-closing adjustments. These and other estimates are subject to change as additional information becomes available and is assessed by us, and agreement is reached on the respective final settlement statements. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Fair value determination:	March 1, 2017
Trade and other current receivables, net	$	6.5
Other current assets		0.6
Property, plant and equipment		255.4
Intangible assets		625.6
Current liabilities		(14.3	)
Other long-term liabilities		(0.4	)
Total identifiable net assets		873.4
Goodwill		159.0
Total fair value of consideration transferred	$	1,032.4

Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value of net assets acquired was approximately $159.0 million, which was recorded as goodwill. As of March 31, 2017, this determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments. As a result, goodwill is also preliminary. The preliminary goodwill is attributable to expected operational and capital synergies. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.

The preliminary fair value of assets acquired included trade receivables of $6.5 million, all of which was expected to be collectible.

The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

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Contingent Consideration

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. During the three months ended March 31, 2017, we recognized $3.2 million as Other expense related to the change in fair value of the contingent consideration. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.

2017 Divestiture

Sale of Venice Gathering System, L.L.C.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

The sale of VGS closed on April 4, 2017, and as a result, we recognized a loss of $16.1 million in our Consolidated Statements of Operations as part of Other operating (income) expense to impair our basis in the VGS assets to its fair value.

Note 5 — Inventories

	March 31, 2017		December 31, 2016
Commodities	$	65.1	$	126.9
Materials and supplies		10.4		10.8
	$	75.5	$	137.7

Note 6 — Property, Plant and Equipment and Intangible Assets

Property, Plant and Equipment

	March 31, 2017			December 31, 2016			Estimated Useful Lives (In Years)
Gathering systems	$	6,777.7		$	6,626.9		5 to 20
Processing and fractionation facilities		3,500.4			3,383.6		5 to 25
Terminaling and storage facilities		1,231.7			1,205.0		5 to 25
Transportation assets		427.9			451.4		10 to 25
Other property, plant and equipment		280.4			274.0		3 to 25
Land		121.5			121.2		—
Construction in progress		610.6			449.8		—
Property, plant and equipment		12,950.2			12,511.9
Accumulated depreciation		(2,986.8	)		(2,821.0	)
Property, plant and equipment, net	$	9,963.4		$	9,690.9
Intangible assets	$	2,662.2		$	2,036.6		15 to 20
Accumulated amortization		(423.4	)		(382.6	)
Intangible assets, net	$	2,238.8		$	1,654.0

Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in

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2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.

The intangible assets acquired in the Permian Acquisition were recorded at a preliminary fair value of $625.6 million pending completion of final valuations. For the purposes of preparing the accompanying financial statements (which include one month of amortization of these intangible assets), we are amortizing these intangible assets over a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations over the upcoming months.

The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.

The estimated annual amortization expense for intangible assets, including the provisional Permian valuations and straight-line treatment is approximately $184.2 million, $177.4 million, $166.4 million, $154.2 million and $144.3 million for each of the years 2017 through 2021.

The changes in our intangible assets are as follows:

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		625.6
Amortization		(40.8	)
Balance at March 31, 2017	$	2,238.8

Note 7 – Goodwill

As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million on our Consolidated Statement of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.

Changes in the net book value of our goodwill are as follows:

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017 (preliminary valuation)		—		—		159.0		159.0
Balance at March 31, 2017, net	$	174.7	$	35.3	$	159.0	$	369.0

Note 8 – Investments in Unconsolidated Affiliates

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with the joint interest owners, which cover their costs of operations (excluding depreciation and amortization). The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments and our share of any operating expenses incurred by the T2 Joint Ventures.

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The following table shows the activity related to our investments in unconsolidated affiliates:

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	240.8
Equity earnings (loss)		3.7			(1.1	)		(2.7	)		(12.5	)		(12.6	)
Cash distributions (1)		(2.7	)		—			—			—			(2.7	)
Contributions for expansion projects (2)		—			0.3			1.1			0.1			1.5
Balance at March 31, 2017	$	47.1		$	57.8		$	117.0		$	5.1		$	227.0

(1) During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.

(2)     Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

Our equity loss for the three months ended March 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment has occurred that is other than temporary. As a result of this evaluation, we have recorded an impairment loss of approximately $12.0 million, which represents our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as the impairment of the unamortized excess fair value resulting from the Atlas mergers.

The carrying values of the T2 gathering joint ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of March 31, 2017, $30.1 million of unamortized excess fair value over the T2 Joint Ventures capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20 year useful lives of the underlying assets.

Note 9 — Accounts Payable and Accrued Liabilities

	March 31, 2017		December 31, 2016
Commodities	$	511.9	$	574.5
Other goods and services		120.7		113.4
Purchase consideration payable		90.0		-
Interest		51.5		52.2
Income and other taxes		22.5		19.1
Other		22.9		14.7
	$	819.5	$	773.9

Accounts payable and accrued liabilities includes $27.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2017 and December 31, 2016.

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Note 10 — Debt Obligations

	March 31, 2017			December 31, 2016
Current:
Accounts receivable securitization facility, due December 2017	$	285.0		$	275.0
Senior unsecured notes, 5% fixed rate, due January 2018		250.5			—
		535.5			275.0
Debt issuance costs, net of amortization		(0.6	)		—
Current maturities of debt		534.9			275.0
Long-term:
Senior secured revolving credit facility, variable rate, due October 2020 (1)		—			150.0
Senior unsecured notes:
5% fixed rate, due January 2018		—			250.5
4⅛% fixed rate, due November 2019		749.4			749.4
6⅜% fixed rate, due August 2022		278.7			278.7
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		580.1			580.1
5⅛% fixed rate, due February 2025		500.0			500.0
5⅜% fixed rate, due February 2027		500.0			500.0
TPL notes, 4¾% fixed rate, due November 2021 (2)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (2)		48.1			48.1
Unamortized premium		0.5			0.5
		3,806.8			4,207.3
Debt issuance costs, net of amortization		(28.5	)		(30.3	)
Long-term debt		3,778.3			4,177.0
Total debt obligations	$	4,313.2		$	4,452.0
Irrevocable standby letters of credit outstanding	$	15.8		$	13.2

(1) As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

(2) Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2017:

	Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
TRP Revolver	3.0% - 5.3%			3.2%
Accounts receivable securitization facility		1.8%		1.8%

Compliance with Debt Covenants

As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements.

Securitization Facility

On February 23, 2017, we amended the accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million.  As of March 31, 2017, there was $285.0 million outstanding under the Securitization Facility.

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Note 11 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following obligations:

	March 31, 2017		December 31, 2016
Asset retirement obligations	$	67.5	$	64.1
Mandatorily redeemable preferred interests		71.9		68.5
Deferred revenue		69.0		69.8
Permian Acquisition contingent consideration		464.8		-
Other liabilities		3.2		2.9
Total long-term liabilities	$	676.4	$	205.3

Asset Retirement Obligations

Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:

Balance at December 31, 2016	$	64.1
Additions (1)		0.4
Change in cash flow estimate		1.7
Accretion expense		1.3
Balance at March 31, 2017	$	67.5

_____________________________________________________________________________________________________________________________________________________________

(1) Amount reflects AROs assumed from the Permian Acquisition

Mandatorily Redeemable Preferred Interests

Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.

For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of March 31, 2017.

The following table shows the changes attributable to mandatorily redeemable preferred interests:

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		0.9
Change in estimated redemption value included in interest expense		2.5
Balance at March 31, 2017	$	71.9

Deferred Revenue

We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. Subsequent annual payments of $43.0 million (subject to an annual inflation factor) will be received

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through 2022. The deferred revenue will be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 and continuing through 2025.

Deferred revenue also includes consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement.  Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.

Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.

The following table shows the components of deferred revenue:

	March 31, 2017		December 31, 2016
Splitter agreement	$	43.0	$	43.0
Gas contract amendment		19.3		19.7
Other deferred revenue		6.7		7.1
Total deferred revenue	$	69.0	$	69.8

The following table shows the changes in deferred revenue:

Balance at December 31, 2016	$	69.8
Additions		-
Revenue recognized		(0.8	)
Balance at March 31, 2017	$	69.0

Contingent Consideration

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The first potential earn-out payment would occur in May 2018. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. For the one month ended March 31, 2017, we had an increase in the fair value of this liability of $3.2 million, bringing the Permian Acquisition contingent consideration to $464.8 million as of March 31, 2017. See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology.

Note 12 — Partnership Units and Related Matters

Distributions

As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations.

The following details the distributions declared or paid by us during the three months ended March 31, 2017:

Three Months	Date Paid		Total			Distributionsto TargaResources
Ended	Or to Be Paid		Distributions			Corp.
March 31, 2017	May 11, 2017	$		209.6	$		206.8
December 31, 2016	February 10, 2017			198.1			195.3

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Contributions

Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions to us, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. During three months ended March 31, 2017, TRC made total capital contributions to us of $655.0 million.     

Preferred Units

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit.   The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

Distributions on our Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

We paid $2.8 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three months ended March 31, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements.  

Subsequent Event

In April 2017, the board of directors of 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, 2017.

Note 13 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of less than $0.1 million for the three months ended March 31, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the three months ended March 31, 2017.

We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues. 

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At March 31, 2017, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2017		2018		2019
Natural Gas	Swaps	MMBtu/d		141,960		100,500		61,383
Natural Gas	Basis Swaps	MMBtu/d		95,963		1,103		-
Natural Gas	Futures	MMBtu/d		-		1,103		-
Natural Gas	Options	MMBtu/d		22,900		9,486		-
NGL	Swaps	Bbl/d		14,143		6,658		5,339
NGL	Futures	Bbl/d		5,702		1,288		-
NGL	Options	Bbl/d		1,647		1,676		-
Condensate	Swaps	Bbl/d		2,690		2,190		1,063
Condensate	Options	Bbl/d		1,380		691		590

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of March 31, 2017				Fair Value as of December 31, 2016
	Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	23.6	$	20.8	$	16.7	$	48.6
	Long-term		21.6		7.9		5.1		26.1
Total derivatives designated as hedging instruments		$	45.2	$	28.7	$	21.8	$	74.7
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.3	$	1.4	$	0.1	$	0.5
Total derivatives not designated as hedging instruments		$	0.3	$	1.4	$	0.1	$	0.5
Total current position		$	23.9	$	22.2	$	16.8	$	49.1
Total long-term position			21.6		7.9		5.1		26.1
Total derivatives		$	45.5	$	30.1	$	21.9	$	75.2

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The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation							Pro forma net presentation
March 31, 2017		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	23.8	$	(20.8	)	$	0.1	$	10.8	$	(7.7	)
	Counterparties without offsetting positions - assets		0.1		-			-		0.1		-
	Counterparties without offsetting positions - liabilities		-		(1.4	)		-		-		(1.4	)
			23.9		(22.2	)		0.1		10.9		(9.1	)
Long Term Position
	Counterparties with offsetting positions or collateral		21.3		(6.6	)		-		16.7		(2.0	)
	Counterparties without offsetting positions - assets		0.3		-			-		0.3		-
	Counterparties without offsetting positions - liabilities		-		(1.3	)		-		-		(1.3	)
			21.6		(7.9	)		-		17.0		(3.3	)
Total Derivatives
	Counterparties with offsetting positions or collateral		45.1		(27.4	)		0.1		27.5		(9.7	)
	Counterparties without offsetting positions - assets		0.4		-			-		0.4		-
	Counterparties without offsetting positions - liabilities		-		(2.7	)		-		-		(2.7	)
		$	45.5	$	(30.1	)	$	0.1	$	27.9	$	(12.4	)
		Gross Presentation							Pro forma net presentation
December 31, 2016		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0	$	5.7	$	(28.0	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(3.0	)		-		-		(3.0	)
			16.8		(49.1	)		7.0		5.7		(31.0	)
Long Term Position
	Counterparties with offsetting positions or collateral		5.1		(18.7	)		-		-		(13.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(7.4	)		-		-		(7.4	)
			5.1		(26.1	)		-		-		(21.0	)
Total Derivatives
	Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0		5.7		(41.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(10.4	)		-		-		(10.4	)
		$	21.9	$	(75.2	)	$	7.0	$	5.7	$	(52.0	)

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of 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 $15.4 million as of March 31, 2017. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended March 31,
Hedging Relationships	2017		2016
Commodity contracts	$	66.2	$	6.7

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	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended March 31,
Location of Gain (Loss)	2017			2016
Revenues	$	(6.1	)	$	24.2

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2017			2016
Commodity contracts	Revenue	$	(0.8	)	$	1.8

Based on valuations as of March 31, 2017, we expect to reclassify commodity hedge related deferred gains of $10.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $2.6 million of losses to be reclassified over the next twelve months.

See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

Note 14 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2017, a net asset position of $15.4 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $47.5 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $79.0 million, ignoring an adjustment for counterparty credit risk.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

• The 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.

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Fair Value Hierarchy

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

• Level 1 – observable inputs such as quoted prices in active markets;

• Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and

• Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.

The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

		March 31, 2017
					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)		$	37.7		$	37.7		$	—		$	35.7		$	2.0
Liabilities from commodity derivative contracts (1)			22.1			22.1			—			20.8			1.3
Permian Acquisition contingent consideration (2)			464.8			464.8			—			—			464.8
TPL contingent consideration (3)			2.7			2.7			—			—			2.7
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			71.7			71.7			—			—			—
TRP Revolver			—			—			—			—			—
Senior unsecured notes			4,057.3			4,169.1			—			4,169.1			—
Accounts receivable securitization facility			285.0			285.0			—			285.0			—
	December 31, 2016
				Fair Value
		Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)		$	21.0		$	21.0		$	—		$	19.6		$	1.4
Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9
TPL contingent consideration (3)			2.6			2.6			—			—			2.6
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			68.0			68.0			—			—			—
TRP Revolver			150.0			150.0			—			150.0			—
Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—
Accounts receivable securitization facility			275.0			275.0			—			275.0			—

(1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2) We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures.

(3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.

Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

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The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

As of March 31, 2017, we had 17 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

The fair value of the Permian Acquisition contingent consideration was determined using a Monte-Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate.  The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) on the Consolidated Statements of Operations.

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability
Balance, December 31, 2016		$	(3.6	)	$	(2.6	)
	Change in fair value of TPL contingent consideration		-			(0.1	)
	Fair value of Permian Acquisition contingent consideration (1)		-			(464.8	)
	New Level 3 derivative instruments		(0.1	)		-
	Transfers out of Level 3 (2)		1.6			-
	Settlements included in Revenue		0.2			-
	Unrealized gain/(loss) included in OCI		2.6			-
Balance, March 31, 2017		$	0.7		$	(467.5	)

(1) Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

(2) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

Note 15 — Related Party Transactions - Targa

Relationship with Targa

We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.

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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,
	2017		2016
Targa billings of payroll and related costs included in operating expense	$	47.0	$	40.2
Targa allocation of general and administrative expense		42.0		39.9
Cash distributions to Targa based on IDR, GP and common unit ownership (1)		195.3		61.4
Cash contributions from Targa related to limited partner ownership (2)		641.9		785.0
Cash contributions from Targa to maintain its 2% general partner ownership		13.1		16.0

_______________________

(1) As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on GP and common unit ownership.

(2) The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partnership and 2% to GP. See Note 12 – Partnership Units and Related Matters.

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Note 16 – Contingencies

Legal Proceedings

Environmental Proceedings

On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014.  The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. On January 31, 2017, Targa Midstream Services LLC executed a settlement agreement with the New Mexico Environment Department which resolved the matter for a civil penalty in the amount of $29,223.

We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Note 17 – Other Operating (Income) Expense

Other operating (income) expense is comprised of the following:

	Three Months Ended March 31,
	2017		2016
(Gain) loss on sale or disposal of assets (1)	$	16.1	$	0.9
Miscellaneous business tax		0.1		0.1
	$	16.2	$	1.0

(1) Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

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Note 18 — Supplemental Cash Flow Information

		Three Months Ended March 31,
		2017				2016
Cash:
Interest paid, net of capitalized interest (1)	$		53.5		$		77.3
Income taxes paid, net of refunds			(0.1	)			1.1
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$		8.3		$		16.9
Impact of capital expenditure accruals on property, plant and equipment			30.0				13.7
Transfers from materials and supplies inventory to property, plant and equipment			0.4				0.5
Contribution of property, plant and equipment to investment in unconsolidated affiliates.			1.0				—
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			1.7				(9.1	)
Non-cash balance sheet movements related to the Permian Acquisition:
Contingent consideration recorded at the acquisition date	$		461.6		$		—
Purchase consideration payable recorded for the Permian Acquisition			90.0				—
Non-cash financing activities:
Cancellation of treasury units	$		—		$		(10.2	)
Accrued distributions on unvested equity awards under share    compensation arrangements			—				0.2

_____________

(1) Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

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Note 19 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas; Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2017
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	166.7	$	1,692.4	$	(1.0	)	$	—		$	1,858.1
Fees from midstream    services		118.2		136.3		—			—			254.5
		284.9		1,828.7		(1.0	)		—			2,112.6
Intersegment revenues
Sales of commodities		713.0		75.4		—			(788.4	)		—
Fees from midstream    services		1.9		7.0		—			(8.9	)		—
		714.9		82.4		—			(797.3	)		—
Revenues	$	999.8	$	1,911.1	$	(1.0	)	$	(797.3	)	$	2,112.6
Operating margin	$	177.4	$	130.1	$	(1.0	)	$	—		$	306.5
Other financial information:
Total assets (1)	$	10,780.4	$	2,687.2	$	44.8		$	57.4		$	13,569.8
Goodwill	$	369.0	$	—	$	—		$	—		$	369.0
Capital expenditures	$	139.2	$	34.6	$	—		$	0.8		$	174.6

(1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

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	Three Months Ended March 31, 2016
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	110.3	$	1,033.9	$	26.8	$	—		$	1,171.0
Fees from midstream    services		115.8		155.6		—		—			271.4
		226.1		1,189.5		26.8		—			1,442.4
Intersegment revenues
Sales of commodities		412.6		47.3		—		(459.9	)		—
Fees from midstream    services		2.1		4.1		—		(6.2	)		—
		414.7		51.4		—		(466.1	)		—
Revenues	$	640.8	$	1,240.9	$	26.8	$	(466.1	)	$	1,442.4
Operating margin	$	115.6	$	157.0	$	26.8	$	—		$	299.4
Other financial information:
Total assets (1)	$	10,219.0	$	2,501.0	$	105.7	$	42.9		$	12,868.6
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0
Capital expenditures	$	103.0	$	73.1	$	—	$	0.8		$	176.9

(1) Corporate assets at the segment level 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,
	2017			2016
Sales of commodities:
Natural gas	$	480.9		$	326.9
NGL		1,314.9			785.8
Condensate		43.6			22.2
Petroleum products		19.8			9.6
Derivative activities		(1.1	)		26.5
		1,858.1			1,171.0
Fees from midstream services:
Fractionating and treating		31.0			30.2
Storage, terminaling, transportation and export		99.7			118.4
Gathering and processing		107.7			105.0
Other		16.1			17.8
		254.5			271.4
Total revenues	$	2,112.6		$	1,442.4

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

	Three Months Ended March 31,
	2017			2016
Reconciliation of operating margin to net income (loss):
Operating margin	$	306.5		$	299.4
Depreciation and amortization expenses		(191.1	)		(193.5	)
General and administrative expenses		(45.5	)		(43.4	)
Goodwill impairment		-			(24.0	)
Interest expense, net		(58.6	)		(46.9	)
Other, net		(37.3	)		18.8
Income tax (expense) benefit		4.7			0.2
Net income (loss)	$	(21.3	)	$	10.6

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.

Overview

Targa Resources Partners LP (“we,” “our,” the “Partnership” or “TRP”) is a Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“TRC” or “Targa”). Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all our outstanding common units.

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 and terminaling crude oil; and

• storing, terminaling and selling refined petroleum products.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, 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.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas; Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of our commodity derivative activities that are included in operating margin.

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Recent Developments

Gathering and Processing Segment Expansion

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 will pay $90.0 million within 90 days of closing (collectively, the "initial purchase price"). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity and an uninstalled 60 MMcf/d plant, which we are in the process of installing in the Delaware Basin with expectations of commencing operations in late 2017. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system.

New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system.

New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and we expect that New Midland's gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

Additional Permian System Processing Capacity

In November 2016, we announced plans to restart the idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system.  The Benedum plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward plant, and was brought back online in the first quarter of 2017.  We expect that the addition of 20 MMcf/d of capacity at our Midkiff plant will increase overall plant capacity of the Midkiff/Consolidator plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. The Midkiff/Consolidator plant complex addition is expected to be completed in the second quarter of 2017. Also in November 2016, we announced plans to build the 200 MMcf/d Joyce plant, which is expected to be completed in the first quarter of 2018. We expect total net growth capital expenditures for the Joyce plant to be approximately $90 million.

In May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Midland system in the Midland Basin. This project includes a new 200 MMcf/d cryogenic processing plant, known as the Johnson plant, which is expected to begin operations in the third quarter of 2018. We expect total net growth capital expenditures for the Johnson plant to be approximately $90 million.

Also in May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Delaware system in the Delaware Basin. This project includes a new 250 MMcf/d cryogenic processing plant, known as the Wildcat plant, which is expected to begin operations in the third quarter of 2018. We expect total net growth capital expenditures for the Wildcat plant to be approximately $130 million.

Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures

In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct the 200 MMcf/d Raptor Plant and approximately 45 miles of associated pipelines. In July 2016,

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Sanchez sold its interest in the gathering joint venture to Sanchez Production Partners, L.P. (“SPP”) and in November 2016, sold its interest in the processing joint venture to SPP. Through the Carnero Joint Ventures, we indirectly own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect SPP's Catarina gathering system to the plant. We hold the capacity on the high pressure gathering pipelines, and pay the gathering joint venture fees for transportation.

The Raptor Plant will accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of the high pressure gathering lines and the plant, which is expected to begin operations in the second quarter of 2017, and will be capable of processing 200 MMcf/d. In February 2017, we announced the addition of compression to increase the processing capacity of the Raptor Plant to 260 MMcf/d, which we expect to be completed in the third quarter of 2017. Prior to the plant being placed in service, we benefited from Sanchez natural gas volumes that were processed at our Silver Oak facilities in Bee County, Texas.

Badlands

During 2017, we expect to invest approximately $150 million to expand our crude gathering and natural gas processing business in the Williston Basin, North Dakota. The expansion includes the addition of pipelines, LACT units, compression and other infrastructure to support continued growth in producer activity.

Sale of Venice Gathering System, L.L.C.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gas Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

In addition to the major projects noted above, we have other growth capital expenditures in 2017 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. We will continue to evaluate other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.

Financing Activities

On February 23, 2017, we amended our account receivable securitization facility (“Securitization Facility”) to increase the facility size to $350.0 million from $275.0 million. 

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

How We Evaluate Our Operations

The profitability of our business segments is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

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Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has increased the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, and adjusted EBITDA.

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Gross Margin

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

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Logistics and Marketing segment gross margin consists primarily of

• service fee revenues (including the pass-through of energy costs included in fee rates),  

• system product gains and losses, and  

• NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change.

The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations. 

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) attributable to TRP before: interest; income taxes; depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expense. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRP. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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Our Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.

	Three Months Ended March 31,
	2017				2016
	(In millions)
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:
Net income (loss)		$	(21.3	)	$	10.6
Depreciation and amortization expense			191.1			193.5
General and administrative expense			45.5			43.4
Goodwill impairment			—			24.0
Interest expense, net			58.6			46.9
Income tax expense (benefit)			(4.7	)		(0.2	)
(Gain) loss on sale or disposition of assets			16.1			0.9
(Gain) loss from financing activities			—			(24.7	)
Other, net			21.2			5.0
Operating margin			306.5			299.4
Operating expenses			151.9			132.0
Gross margin		$	458.4		$	431.4

	Three Months Ended March 31,
	2017			2016
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP	$	(27.3	)	$	7.6
Interest expense, net		58.6			46.9
Income tax expense (benefit)		(4.7	)		(0.2	)
Depreciation and amortization expense		191.1			193.5
Goodwill impairment		—			24.0
(Gain) loss on sale or disposition of assets		16.1			0.9
(Gain) loss from financing activities		—			(24.7	)
(Earnings) loss from unconsolidated affiliates		12.6			4.8
Distributions from unconsolidated affiliates and preferred partner interests, net		4.2			5.8
Change in contingent consideration		3.3			—
Compensation on TRP equity grants		—			2.2
Transaction costs related to business acquisitions		5.1			—
Splitter Agreement (1)		10.8			—
Risk management activities		3.6			5.9
Noncontrolling interests adjustments (2)		(4.3	)		(5.8	)
TRP Adjusted EBITDA	$	269.1		$	260.9

(1) The Splitter Agreement adjustment represents the recognition of the annual cash payment received under the condensate splitter agreement recognized over the four quarters following receipt.

(2) Noncontrolling interest portion of depreciation and amortization expense.

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Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations:

		Three Months Ended March 31,
		2017			2016			2017 vs. 2016
	(In millions, except operating statistics and price amounts)
Revenues:
Sales of commodities		$	1,858.1		$	1,171.0		$	687.1			59	%
Fees from midstream services			254.5			271.4			(16.9	)		(6	%)
Total revenues			2,112.6			1,442.4			670.2			46	%
Product purchases			1,654.2			1,011.0			643.2			64	%
Gross margin (1)			458.4			431.4			27.0			6	%
Operating expenses			151.9			132.0			19.9			15	%
Operating margin (1)			306.5			299.4			7.1			2	%
Depreciation and amortization expense			191.1			193.5			(2.4	)		(1	%)
General and administrative expense			45.5			43.4			2.1			5	%
Goodwill impairment			—			24.0			(24.0	)		(100	%)
Other operating (income) expense			16.2			1.0			15.2		NM
Income from operations			53.7			37.5			16.2			43	%
Interest expense, net			(58.6	)		(46.9	)		(11.7	)		25	%
Equity earnings (loss)			(12.6	)		(4.8	)		(7.8	)		163	%
Gain from financing activities			—			24.7			(24.7	)		(100	%)
Other income (expense)			(8.5	)		(0.1	)		(8.4	)	NM
Income tax (expense) benefit			4.7			0.2			4.5		NM
Net income (loss)			(21.3	)		10.6			(31.9	)	NM
Less: Net income attributable to noncontrolling interests			6.0			3.0			3.0			100	%
Net income (loss) attributable to Targa Resources Partners LP		$	(27.3	)	$	7.6		$	(34.9	)	NM
Financial and operating data:
Financial data:
Adjusted EBITDA (1)		$	269.1		$	260.9		$	8.2			3	%
Capital expenditures			174.6			176.9			(2.3	)		(1	%)
Business acquisition (2)			1,032.4			—			1,032.4			—
Operating statistics: (3)
Crude oil gathered, Badlands, MBbl/d			113.5			108.1			5.4			5	%
Crude oil gathered, Permian, MBbl/d (4)			9.2			—			9.2			—
Plant natural gas inlet, MMcf/d (5)(6)			3,242.1			3,406.0			(163.9	)		(5	%)
Gross NGL production, MBbl/d			291.8			284.7			7.1			2	%
Export volumes, MBbl/d (7)			217.5			181.0			36.5			20	%
Natural gas sales, BBtu/d (6)(8)			1,870.2			1,974.6			(104.4	)		(5	%)
NGL sales, MBbl/d (8)			533.6			547.8			(14.2	)		(3	%)
Condensate sales, MBbl/d			10.7			9.5			1.2			13	%

(1) Gross margin, operating margin, and adjusted EBITDA are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”

(2) Includes the $90.0 million payable which will be settled within 90 days from March 1, 2017, and the preliminary acquisition date fair value of the potential earn-out payments of $461.6 million due in 2018 and 2019.

(3) These volume statistics are presented with the numerator as the total volume sold during the quarter and the denominator as the number of calendar days during the quarter.

(4) Includes operations from the Permian Acquisition for the period effective March 1, 2017. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while the denominator is the number of calendar days during the quarter.

(5) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume.

(6) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(7) Export volumes represent the quantity of NGL products delivered to third party customers at our Galena Park Marine Terminal that are destined for international markets.

(8) Includes the impact of intersegment eliminations.

NM      Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

The increase in commodity sales was primarily due to higher commodity prices ($757.8 million), partially offset by decreased volumes ($45.4 million) and the impact of hedge settlements ($25.3 million). Additionally, fee-based and other revenues decreased primarily due to lower export fees.

The increase in product purchases was primarily due to the impact of higher commodity prices, partially offset by decreased volumes.

The higher operating margin and gross margin in 2017 reflects increased segment margin results for Gathering and Processing, partially offset by decreased Logistics and Marketing segment margins. Operating expenses increased compared to 2016 due to higher

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maintenance in the Logistics and Marketing segment and plant and system expansions in the Permian region. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The decrease in depreciation and amortization expenses reflects the impact of fully depreciated property assets and lower scheduled amortization on the Badlands intangibles, partially offset by one month of operations of the Permian Acquisition in 2017 and the impact of growth investments, primarily CBF Train 5 which went into service in June 2016.

General and administrative expenses increased primarily due to higher compensation and benefits.

We recognized an impairment of goodwill in the first quarter of 2016 of $24.0 million to finalize the 2015 provisional impairment of goodwill. The impairment charge related to goodwill acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”).

Other operating (income) expense in 2017 includes the loss due to the reduction in the carrying value of our ownership interest in the Venice Gathering System in connection with the April 4, 2017 sale.

Net interest expense increased primarily due to higher non-cash interest expense related to the mandatorily redeemable preferred interests liability that is revalued quarterly at its estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests increased in 2017, whereas it decreased in 2016. This increase was partially offset by the impact of lower average outstanding borrowings during 2017.

Higher equity losses in 2017 reflects a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.

During 2016, we recorded a gain of $24.7 million on open debt market repurchases and other financing activities. There were no repurchases or redemptions of our long-term debt in 2017.

Other expense in 2017 was primarily attributable to $5.1 million of non-recurring transaction costs related to the Permian Acquisition and a $3.2 million increase in the fair value of the Permian Acquisition contingent consideration liability from the acquisition date to March 31, 2017.

The increase in income tax benefit was primarily due to a Texas Margin Tax refund in the first quarter of 2017.

Net income attributable to noncontrolling interests increased primarily due to our October 2016 acquisition of the 37% interest of Versado that we did not already own and higher earnings at our joint ventures.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

		Gathering and Processing		Logistics and Marketing		Other			Total
	(In millions)
Three Months Ended:
March 31, 2017		$	177.4	$	130.1	$	(1.0	)	$	306.5
March 31, 2016			115.6		157.0		26.8			299.4

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Gathering and Processing Segment

	Three Months Ended March 31,
	2017		2016		2017 vs. 2016
Gross margin	$	263.0	$	194.1	$	68.9		35	%
Operating expenses		85.6		78.5		7.1		9	%
Operating margin	$	177.4	$	115.6	$	61.8		53	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4)		275.6		243.5		32.1		13	%
WestTX		536.5		461.0		75.5		16	%
Total Permian Midland		812.1		704.5		107.6
Sand Hills (4)		139.5		151.1		(11.6	)	(8	%)
Versado		198.5		180.0		18.5		10	%
Total Permian Delaware		338.0		331.1		6.9
Total Permian		1,150.1		1,035.6		114.5
SouthTX		171.8		175.7		(3.9	)	(2	%)
North Texas		282.5		327.5		(45.0	)	(14	%)
SouthOK		440.4		457.9		(17.5	)	(4	%)
WestOK		393.1		487.0		(93.9	)	(19	%)
Total Central		1,287.8		1,448.1		(160.3	)
Badlands (5)		46.0		53.7		(7.7	)	(14	%)
Total Field		2,483.9		2,537.4		(53.5	)
Coastal		758.2		868.6		(110.4	)	(13	%)
Total		3,242.1		3,406.0		(163.9	)	(5	%)
Gross NGL production, MBbl/d (3)
SAOU (4)		33.3		29.2		4.1		14	%
WestTX		69.5		52.4		17.1		33	%
Total Permian Midland		102.8		81.6		21.2
Sand Hills (4)		14.8		15.7		(0.9	)	(6	%)
Versado		23.1		21.9		1.2		5	%
Total Permian Delaware		37.9		37.6		0.3
Total Permian		140.7		119.2		21.5
SouthTX		16.6		23.1		(6.5	)	(28	%)
North Texas		32.0		35.7		(3.7	)	(10	%)
SouthOK		40.9		28.0		12.9		46	%
WestOK		22.8		26.9		(4.1	)	(15	%)
Total Central		112.3		113.7		(1.4	)
Badlands		5.5		7.6		(2.1	)	(28	%)
Total Field		258.5		240.5		18.0
Coastal		33.3		44.2		(10.9	)	(25	%)
Total		291.8		284.7		7.1		2	%
Crude oil gathered, Badlands, MBbl/d		113.5		108.1		5.4		5	%
Crude oil gathered, Permian, MBbl/d (4)		9.2		—		9.2		—
Natural gas sales, BBtu/d (3)		1,562.2		1,687.2		(125.0	)	(7	%)
NGL sales, MBbl/d (3)		227.6		219.3		8.3		4	%
Condensate sales, MBbl/d		10.7		9.5		1.2		13	%
Average realized prices (6):
Natural gas, $/MMBtu		2.86		1.75		1.11		63	%
NGL, $/gal		0.50		0.28		0.22		79	%
Condensate, $/Bbl		44.98		25.65		19.33		75	%

(1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(2) Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

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(4) Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes are included within Sand Hills. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while the denominator is the number of calendar days during the quarter.

(5) Badlands natural gas inlet represents the total wellhead gathered volume.

(6) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

The increase in gross margin was primarily due to higher commodity prices and the inclusion of the Permian Acquisition for one month in 2017 partially offset by lower throughput volumes. Inlet volumes for Field Gathering and Processing were slightly lower with increases at WestTX, SAOU and Versado offset by decreases at the other areas. The inlet volume decrease for Coastal Gathering and Processing which generates significantly lower margins than does Field Gathering and Processing, accounted for over 67% of the overall inlet volume decrease. Despite overall lower inlet volumes, NGL production and NGL sales increased primarily due to increased plant recoveries including additional ethane recovery. Natural gas sales decreased due to lower inlet volumes and increased ethane recovery. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition and in Badlands due to system expansions. Badlands natural gas volumes decreased primarily due to severe winter weather.

The increase in operating expenses was primarily driven by plant and system expansions in the Permian region and the inclusion of the Permian Acquisition for one month of 2017.  Operating expenses in other areas were relatively flat.

Gross Operating Statistics Compared to Actual Reported

The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:

	Three Months Ended March 31, 2017
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
SAOU (4)		275.6		100	%		275.6		275.6
WestTX (5) (6)		736.9		73	%		536.5		536.5
Total Permian Midland		1,012.5					812.1		812.1
Sand Hills (4)		139.5		100	%		139.5		139.5
Versado (7)		198.5		100	%		198.5		198.5
Total Permian Delaware		338.0					338.0		338.0
Total Permian		1,350.5					1,150.1		1,150.1
SouthTX		171.8	Varies (8)				161.6		171.8
North Texas		282.5		100	%		282.5		282.5
SouthOK		440.4	Varies (9)				366.1		440.4
WestOK		393.1		100	%		393.1		393.1
Total Central		1,287.8					1,203.3		1,287.8
Badlands (10)		46.0		100	%		46.0		46.0
Total Field		2,684.3					2,399.4		2,483.9
Gross NGL production, MBbl/d (2)
SAOU (4)		33.3		100	%		33.3		33.3
WestTX (5) (6)		95.5		73	%		69.5		69.5
Total Permian Midland		128.8					102.8		102.8
Sand Hills (4)		14.8		100	%		14.8		14.8
Versado (7)		23.1		100	%		23.1		23.1
Total Permian Delaware		37.9					37.9		37.9
Total Permian		166.7					140.7		140.7
SouthTX		16.6	Varies (8)				15.7		16.6
North Texas		32.0		100	%		32.0		32.0
SouthOK		40.9	Varies (9)				34.2		40.9
WestOK		22.8		100	%		22.8		22.8
Total Central		112.3					104.7		112.3
Badlands		5.5		100	%		5.5		5.5
Total Field		284.5					250.9		258.5

(1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

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(3) For these volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(4) Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes are included within Sand Hills.

(5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(6) Includes the Buffalo Plant that commenced commercial operations in April 2016.

(7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(8) SouthTX includes the Silver Oak II plant, of which Targa Pipeline Partners, L.P. (“TPL”) has owned a 90% interest since October 2015, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(9) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(10) Badlands natural gas inlet represents the total wellhead gathered volume.

	Three Months Ended March 31, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
SAOU		243.5		100	%		243.5		243.5
WestTX (4)		633.2		73	%		461.0		461.0
Total Permian Midland		876.7					704.5		704.5
Sand Hills		151.1		100	%		151.1		151.1
Versado (5)		180.0		63	%		113.4		180.0
Total Permian Delaware		331.1					264.5		331.1
Total Permian		1,207.8					969.0		1,035.6
SouthTX		175.7		100	%		175.7		175.7
North Texas		327.5		100	%		327.5		327.5
SouthOK		457.9	Varies (6)				380.9		457.9
WestOK		487.0		100	%		487.0		487.0
Total Central		1,448.1					1,371.1		1,448.1
Badlands (7)		53.7		100	%		53.7		53.7
Total Field		2,709.6					2,393.8		2,537.4
Gross NGL production, MBbl/d (2)
SAOU		29.2		100	%		29.2		29.2
WestTX (4)		72.0		73	%		52.4		52.4
Total Permian Midland		101.2					81.6		81.6
Sand Hills		15.7		100	%		15.7		15.7
Versado (5)		21.9		63	%		13.8		21.9
Total Permian Delaware		37.6					29.5		37.6
Total Permian		138.8					111.1		119.2
SouthTX		23.1		100	%		23.1		23.1
North Texas		35.7		100	%		35.7		35.7
SouthOK		28.0	Varies (6)				24.7		28.0
WestOK		26.9		100	%		26.9		26.9
Total Central		113.7					110.4		113.7
Badlands		7.6		100	%		7.6		7.6
Total Field		260.1					229.1		240.5

(1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

(3) For these volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(4) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(6) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(7) Badlands natural gas inlet represents the total wellhead gathered volume.

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Logistics and Marketing Segment

		Three Months Ended March 31,
		2017		2016		2017 vs. 2016
	(In millions)
Gross margin		$	196.4	$	210.6	$	(14.2	)	(7	%)
Operating expenses			66.3		53.6		12.7		24	%
Operating margin		$	130.1	$	157.0	$	(26.9	)	(17	%)
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)			304.9		295.5		9.4		3	%
LSNG treating volumes (2)			34.5		21.0		13.5		64	%
Benzene treating volumes (2)			23.5		21.0		2.5		12	%
Export volumes, MBbl/d (4)			217.5		181.0		36.5		20	%
NGL sales, MBbl/d			502.0		482.0		20.0		4	%
Average realized prices:
NGL realized price, $/gal		$	0.66	$	0.41	$	0.25		61	%

________________________________________________________

(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(2) Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy.  As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses.

(3) Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.

(4) Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

Logistics and Marketing gross margin decreased due to lower LPG export margin and lower wholesale and marketing margin, partially offset by higher fractionation margin, higher terminaling and storage throughput and higher treating margin. LPG export margin decreased due to lower fees partially offset by higher volumes. Wholesale and marketing margin decreased primarily due to less favorable wholesale supply opportunities in 2017 compared to the same period last year and lower marketing gains. Fractionation margin increased due to higher system product gains, higher fees and higher supply volume. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Treating margin increased slightly due to higher volumes partially offset by lower fees.

Operating expenses increased due to higher maintenance primarily associated with unusual one-time events, higher fuel and power, and higher compensation and benefits.

Other

	Three Months Ended March 31,
	2017			2016		2017 vs. 2016
	(In millions)
Gross margin	$	(1.0	)	$	26.8	$	(27.8	)
Operating margin	$	(1.0	)	$	26.8	$	(27.8	)

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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The following table provides a breakdown of the change in Other operating margin:

	Three Months Ended March 31, 2017								Three Months Ended March 31, 2016
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)		Gain (Loss)		2017 vs. 2016
Natural gas (BBtu)		10.5	$	0.02		$	0.2			9.5	$	1.40	$	13.2	$	(13.0	)
NGL (MMgal)		43.3		(0.04	)		(1.8	)		14.3		0.27		3.8		(5.6	)
Crude oil (MBbl)		0.2		5.35			1.2			0.2		35.22		7.1		(5.9	)
Non-hedge accounting (2)							(0.8	)						2.7		(3.5	)
Ineffectiveness (3)							0.2							—		0.2
						$	(1.0	)					$	26.8	$	(27.8	)

(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

(2) Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.

(3) Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of TPL that do not qualify for hedge accounting.

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received total derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.

Liquidity and Capital Resources

As of March 31, 2017, we had $71.7 million of “Cash and cash equivalents,” on our Consolidated Balance Sheet. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices, weather and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flows from operations, contributions from TRC that are funded through TRC’s access to debt and equity markets, borrowings under the TRP Revolver, borrowings under the Securitization Facility, and access to debt markets. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facility, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

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Short-term Liquidity

Our short-term liquidity as of May 1, 2017, was:

		May 1, 2017
		(In millions)
Cash on hand		$	113.6
Total availability under the TRP Revolver			1,600.0
Total availability under the Securitization Facility			250.2
			1,963.8
Less:	Outstanding borrowings under the TRP Revolver		(180.0	)
	Outstanding borrowings under the Securitization Facility		(250.2	)
	Outstanding letters of credit under the TRP Revolver		(20.2	)
	Total liquidity	$	1,513.4

Other potential capital resources associated with our existing arrangements include:

• Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on October 7, 2020.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable that are tied to commodity sales and purchases are relatively balanced, with receivables from NGL customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Our working capital, exclusive of current debt obligations, decreased $197.3 million from December 31, 2016 to March 31, 2017.  The major items contributing to this decrease were the establishment of the $90 million purchase consideration payable related to the Permian Acquisition, reduction in inventory due to higher export volumes and the seasonality of our wholesale business, a decrease in our net commodity receivables and payables due to lower commodity revenue in March 2017 as compared with December 2016 and reduced commodity purchases partially offset by an increase in our net risk management working capital position due to changes in the forward prices of commodities and a higher cash balance. The increase of $260.5 million in current debt obligations was due to reclassification of the senior note due January 2018 from long-term to current, as well as the increased receivables available for the Securitization Facility.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from debt offerings should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and cash distributions to Targa for at least the next twelve months.

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Long-term Financing

Long-term financing consists of long-term debt obligations and preferred units.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date, and in some cases, a make-whole premium. As of March 31, 2017 and December 31, 2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $3,806.3 million and $4,206.8 million, respectively.

The majority of our long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP Revolver. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of March 31, 2017, we do not have any interest rate hedges.

To date, we do not believe our debt balances have adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions, see Note 10 - Debt Obligations to our consolidated financial statements.  For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” 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%. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption.

Compliance with Debt Covenants

As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements.

Cash Flow

Cash Flows from Operating Activities

The Consolidated Statements of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented.

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The following table displays our operating cash flows using the direct method as a supplement to the presentation in our consolidated financial statements:

	Three Months Ended March 31,
	2017			2016			2017 vs. 2016
	(In millions)
Cash flows from operating activities:
Cash received from customers	$	2,243.2		$	1,483.8		$	759.4
Cash received from (paid to) derivative counterparties		1.2			28.1			(26.9	)
Cash distributions from equity investments (1)		2.7			—			2.7
Cash outlays for:
Product purchases		1,646.0			1,022.4			623.6
Operating expenses		169.2			120.9			48.3
General and administrative expense		58.9			48.3			10.6
Interest paid, net of amounts capitalized (2)		53.5			77.3			(23.8	)
Income taxes paid, net of refunds		(0.1	)		1.1			(1.2	)
Other cash (receipts) payments		6.4			(0.1	)		6.5
Net cash provided by operating activities	$	313.2		$	242.0		$	71.2

(1) Excludes $3.4 million included in investing activities for the three months ended March 31, 2016 related to distributions from GCF and the T2 Joint Ventures that exceeded cumulative equity earnings. We did not have distributions that exceeded cumulative earnings for the three months ended March 31, 2017.

(2) Net of capitalized interest paid of $1.7 million and $4.8 million included in investing activities for the three months ended March 31, 2017 and 2016.

Higher commodity prices were the primary contributor to increased cash collections and payments for product purchases in 2017 compared to 2016. Derivative settlements remained an overall source of revenue during 2017, but at a lower amount as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2017 in comparison to 2016. Interest payments are lower this year largely due to repurchases of debt in the first quarter 2016, offset by the timing of payments of interest on two new series of notes we issued in 2016. Cash payments for general and administrative expenses and operating expenses were higher, primarily due to increases in compensation and benefits, contractor and other professional services, coupled with higher utilities and higher maintenance. Other cash payments in 2017 were higher mainly due to transaction expenses associated with the Permian Acquisition in 2017.

Cash Flows from Investing Activities

Three Months Ended March 31,
2017			2016			2017 vs. 2016
(In millions)
$	(625.5	)	$	(188.0	)	$	(437.5	)

Cash used in investing activities increased in 2017 compared to 2016, primarily due to the $480.8 million outlay for the cash portion due at closing of the Permian Acquisition consideration. An additional $90 million will be paid during the second quarter of 2017, as well as potential contingent consideration payments in 2018 and 2019. Growth and maintenance capital expenditures decreased $45.9 million during 2017 reflecting the completion of major growth projects during 2016.

Cash Flows from Financing Activities

	Three Months Ended March 31,
	2017			2016
Source of Financing Activities, net	(In millions)
Debt, including financing costs	$	(140.1	)	$	(679.9	)
Equity offerings, net of financing costs		-			(7.5	)
Distributions		(198.1	)		(203.5	)
Contributions from TRC and General Partner		655.0			801.0
Other		(0.8	)		3.8
Net cash provided by (used in) financing activities	$	316.0		$	(86.1	)

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In 2017, we realized a net source of cash from financing activities, primarily due to contributions from TRC, partially offset by payments of distributions to TRC and repayments of our credit facilities.

In 2016, we incurred a net use of cash from financing activities, primarily due to a net reduction of debt outstanding and payment of distributions to TRC, offset by contributions from TRC and our general partner. With the contributions from TRC, we repurchased a portion of our senior notes through open market repurchases generally at a discount to par values and repaid a portion of the outstanding borrowings under the TRP Revolver.

Distributions

As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations of the “Consolidated Financial Statements” included in this quarterly report.

The following table details the distributions declared and/or paid by us during the three months ended March 31, 2017.

Three Months	Date Paid		Total			Distributionsto TargaResources
Ended	Or to Be Paid		Distributions			Corp.
March 31, 2017	May 11, 2017	$		209.6	$		206.8
December 31, 2016	February 10, 2017			198.1			195.3

Preferred Units

Distributions on our Preferred Units are declared and paid monthly. As of March 31, 2017, we have 5,000,000 Preferred Units outstanding. For the three months ended March 31, 2017 $2.8 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for March, which were paid subsequently on April 17, 2017.

In April 2017, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on May 15, 2017.

Capital Requirements

Our capital requirements relate to capital expenditures, which are classified as expansion expenditures including business acquisitions and maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

	Three Months Ended March 31,
	2017			2016
Capital expenditures :	(In millions)
Consideration for business acquisition	$	1,032.4		$	—
Contingent consideration (1)		(461.6	)		—
Purchase consideration payable (2)		(90.0	)		—
Business acquisition, net of cash acquired		480.8			—
Expansion		148.9			161.9
Maintenance		25.7			15.0
Gross capital expenditures		174.6			176.9
Transfers from materials and supplies inventory to    property, plant and equipment		(0.4	)		(0.5	)
Decrease in capital project payables and accruals		(30.0	)		13.7
Cash outlays for capital projects		144.2			190.1
Total	$	625.0		$	190.1

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(1) See Note 4 – Business Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the preliminary estimated fair value of contingent consideration at the acquisition date.

(2) The payable will be settled in cash within 90 days from March 1, 2017.

We currently estimate that we will invest at least $960 million in net growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. Our expansion capital expenditures decreased in the first quarter of 2017 as compared to 2016, primarily due to lower CBF train 5 construction costs, partially offset by the restart of the Benedum Plant and the commencement of construction of the Joyce Plant. Our maintenance capital expenditures increased for 2017 as compared to 2016, primarily due to higher numbers of compressors reaching the end of their maintenance cycles in the first quarter 2017 versus 2016 and increased well connects.

Off-Balance Sheet Arrangements

As of March 31, 2017, there were $38.8 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas equity volumes, NGL equity volumes and condensate equity volumes and future commodity purchases and sales through 2019. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Commodity Price Risk

A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of natural gas and/or NGLs as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2017, we have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing operations, (ii) NGL and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements and (iii) future commodity purchases and sales in our Logistics and Marketing segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes

49

without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGL hedges’ fair values are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices.  Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

Our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $(6.7) million and $21.2 million, during the three months ended March 31, 2017 and 2016, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. 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.

Our risk management position has moved from a net liability position of $53.3 million at December 31, 2016 to a net asset position of $15.4 million at March 31, 2017. The fixed prices we currently expect to receive on derivative contracts are above the aggregate forward prices for commodities related to those contracts, creating this net asset position.

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As of March 31, 2017, we had the following derivative instruments that will settle during the years shown below:

Natural GAS

Instrument		Price
Type	Index	$/MMBtu					MMBtu/d							Fair Value
							2017			2018		2019		(In millions)
Gathering & Processing
Swap	IF-Waha		2.87					103,600			-		-		(2.0	)
Swap	IF-Waha		2.68					-			73,600		-		3.7
Swap	IF-Waha		2.77					-			-		45,383		6.5
								103,600			73,600		45,383
Swap	IF-PB		2.51					10,900			-		-		(1.0	)
Swap	IF-PB		2.51					-			10,900		-		0.3
								10,900			10,900		-
Swap	IF-PEPL		2.6835					16,000			-		-		(1.1	)
Swap	IF-PEPL		2.6835					-			16,000		-		0.4
Swap	IF-PEPL		2.6835					-			-		16,000		1.6
								16,000			16,000		16,000
Swap	NG-NYMEX		3.99					12,000			-		-		2.3
		Put Price			Call Price
Collar	IF-Waha		3.00			3.67		7,500			-		-		0.4
Collar	IF-Waha		3.25			4.20		-			1,849		-		0.2
								7,500			1,849		-
		Put Price			Call Price
Collar	IF-PB		2.80			3.50		15,400			-		-		0.6
Collar	IF-PB		3.00			3.65		-			7,637		-		1.4
								15,400			7,637		-
Basis Swap	EP-PERMIAN		(0.1444	)				6,000			-		-		0.5
Basis Swap	PEPL		(0.3308	)				6,000			-		-		0.1
Gathering & Processing total								177,400			109,986		61,383		13.9
Other (1)
Swap	NG-NYMEX		(3.1602	)				(540	)		-		-	$	0.0
Basis Swap	Various		(0.1930	)				83,964			1,103		-		(1.2	)
Future	Various		3.2640					-			1,103		-		(0.1	)
Other total								83,424			2,206		-	$	(1.3	)
														$	12.6

(1) Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.

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NGLs

Instrument		Price
Type	Index	$/gal				Bbl/d						Fair Value
						2017		2018		2019		(In millions)
Gathering & Processing
Swap	C2-OPIS-MB		0.2746				4,498		-		-		0.8
Swap	C2-OPIS-MB		0.2776				-		2,368		-		(1.0	)
Swap	C2-OPIS-MB		0.2932				-		-		1,710		(1.0	)
Total							4,498		2,368		1,710
Swap	C3-OPIS-MB		0.6505				6,005		-		-		2.2
Swap	C3-OPIS-MB		0.5530				-		2,650		-		(1.3	)
Swap	C3-OPIS-MB		0.5530				-		-		2,650		(0.1	)
Total							6,005		2,650		2,650
Swap	IC4-OPIS-MB		0.8080				630		-		-		0.2
Swap	IC4-OPIS-MB		0.7487				-		230		-		0.0
Swap	IC4-OPIS-MB		0.7200				-		-		110		(0.0	)
Total							630		230		110
Swap	NC4-OPIS-MB		0.7960				1,500		-		-		0.5
Swap	NC4-OPIS-MB		0.7388				-		600		-		0.2
Swap	NC4-OPIS-MB		0.7050				-		-		300		(0.0	)
Total							1,500		600		300
Swap	C5-OPIS-MB		1.1056				1,510		-		-		(0.6	)
Swap	C5-OPIS-MB		1.0385				-		810		-		(0.7	)
Swap	C5-OPIS-MB		1.0825				-		-		569		0.3
Total							1,510		810		569
		Put Price		Call Price
Collar	C2-OPIS-MB		0.240		0.290		410		-		-		0.0
		Put Price		Call Price
Collar	C3-OPIS-MB		0.570		0.68625		380		-		-		0.0
		Put Price		Call Price
Collar	C5-OPIS-MB		1.210		1.415		130		-		-		0.2
Collar	C5-OPIS-MB		1.230		1.385		-		32		-		0.1
Total							130		32		-
Gathering & Processing total							15,063		6,690		5,339	$	(0.2	)
Other (1)(2)
Future	C2-OPIS-MB		0.2715				4,091		-		-		(0.1	)
Future	C2-OPIS-MB		0.3015				-		1,288		-		(0.2	)
Total							4,091		1,288		-
Future	C3-OPIS-MB		0.6618				1,400		-		-		0.4
Future	IC4-OPIS-MB		0.7800				218		-		-		(0.0	)
Future	Heating Oil		1.5950				(7)		-		-		(0.0	)
	Put Price
Option	C2-OPIS-MB		0.2694				727		-		-		0.2
Option	C2-OPIS-MB		0.2963				-		1,644		-		0.8
Total							727		1,644		-
Other total							6,429		2,932		-	$	1.1
												$	0.9

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(1) Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.

(2) The “Future” line items are comprised of futures transactions entered into on both the Intercontinental Exchange (“ICE”) and Chicago Mercantile Exchange (“CME”).

CONDENSATE

Instrument		Price
Type	Index	$/Bbl				Bbl/d						Fair Value
						2017		2018		2019		(In millions)
Gathering & Processing
Swap	WTI-NYMEX		54.54				2,690		-		-		2.1
Swap	WTI-NYMEX		48.79				-		2,190		-		(2.4	)
Swap	WTI-NYMEX		51.19				-		-		1,063		(0.1	)
							2,690		2,190		1,063
		Put Price		Call Price
Collar	WTI-NYMEX		54.04		64.09		1,380		-		-		1.7
Collar	WTI-NYMEX		49.76		58.50		-		691		-		0.4
Collar	WTI-NYMEX		48.00		56.25		-		-		590		0.2
							1,380		691		590
Total							4,070		2,881		1,653
													1.9

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). For derivative instruments not designated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity contract, the valuations are classified as Level 3 within the fair value hierarchy. See Note 14 - Fair Value Measurements in this Quarterly Report for more information regarding classifications within the fair value hierarchy.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of March 31, 2017, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of March 31, 2017, we had $285.0 million in outstanding variable rate borrowings under the TRP Revolver and Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $2.9 million.

Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a

53

counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with all our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $30.1 million as of March 31, 2017. The range of losses attributable to our individual counterparties would be between $0.1 million and $13.3 million, depending on the counterparty in default.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure risk, including initial and subsequent credit risk analyses, credit limits and terms and credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable as of March 31, 2017, our operating income would decrease by $5.4 million in the year of the assessment.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting 

There have been no changes in our internal control over financial reporting that occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

54

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 16 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A. Risk Factors.

For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our Annual Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Recent Sales of Unregistered Securities.

Not applicable.

Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers.

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

55

Item 6. Exhibits.

Number	Description
2.1***	Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Delaware Midstream, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.2***	Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Energy, LLC (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.3***	Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Midland Midstream, LLC (incorporated by reference to Exhibit 2.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
3.1	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.2	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.3	Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)).
3.4	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
4.1	Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)).
4.2*	Supplemental Indenture dated March 10, 2017 to Indenture dated January 31, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.3*	Supplemental Indenture dated March 10, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.4*	Supplemental Indenture dated March 10, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.5*	Supplemental Indenture dated March 10, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.6*	Supplemental Indenture dated March 10, 2017 to Indenture dated January 30, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.7*	Supplemental Indenture dated March 10, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.8*	Supplemental Indenture dated March 10, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

56

Number	Description
10.1	Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, and PNC Bank, National Association, as administrator, purchaser agent and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 24, 2017 (File No. 001-33303)).
10.2	Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)).
10.3+	Targa Resources Corp. 2017 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partner’s Current Report on Form 8-K filed January 25, 2017(File No. 001-33303)).
31.1*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

** Furnished herewith

*** The schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

+ Management contract or compensatory plan or arrangement

57

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Targa Resources Partners LP (Registrant)
	By:	Targa Resources GP LLC,
		its general partner
Date: May 4, 2017	By:	/s/ Matthew J. Meloy
		Matthew J. Meloy
		Executive Vice President and Chief Financial Officer
		(Authorized Officer and Principal Financial Officer)

58

EX-4.2

Exhibit 4.2

#5416445.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of January 31, 2012 providing for the issuance of 6 3/8% Senior Notes due 2022 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

EX-4.3

Exhibit 4.3

#5416449.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 25, 2012 providing for the issuance of 5 1/4% Senior Notes due 2023 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

EX-4.4

Exhibit 4.4

#5416502.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 14, 2013 providing for the issuance of 4 1/4% Senior Notes due 2023 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By: /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

EX-4.5

Exhibit 4.5

#5416503.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 28, 2014 providing for the issuance of 4.125% Senior Notes due 2019 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

EX-4.6

Exhibit 4.6

#5416507.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of January 30, 2015 providing for the issuance of 5% Senior Notes due 2018 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

EX-4.7

Exhibit 4.7

#5416513.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of September 14, 2015 providing for the issuance of 6 3/4% Senior Notes due 2024 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

EX-4.8

Exhibit 4.8

#5416515.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 6, 2016 providing for the issuance of 5 1/8% Senior Notes due 2025 and 5 3/8% Senior Notes due 2027 (collectively, the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date firstabove written.

GUARANTEEING SUBSIDIARY

Targa SouthOk NGL Pipeline LLC

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By:  /s/ Shazia Flores

Authorized Signatory

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Joe Bob Perkins, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 4, 2017

By:	/s/ Joe Bob Perkins
Name:	Joe Bob Perkins
Title:	Chief Executive Officer of Targa Resources GP LLC, the general partner of Targa Resources Partners LP
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Matthew J. Meloy, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 4, 2017

By:	/s/ Matthew J. Meloy
Name:	Matthew J. Meloy
Title:	Executive Vice President and Chief Financial Officer of Targa Resources GP LLC, the general partner of Targa Resources Partners LP
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Joe Bob Perkins, as Chief Executive Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ Joe Bob Perkins
Name:	Joe Bob Perkins
Title:	Chief Executive Officer
of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

Date: May 4, 2017

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew J. Meloy, as Chief Financial Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ Matthew J. Meloy
Name:	Matthew J. Meloy
Title:	Executive Vice President and Chief Financial Officer
of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

Date: May 4, 2017

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	Targa Resources Partners LP
Trading Symbol	NGLS
Entity Central Index Key	0001379661
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017

XML

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 71.7	$ 68.0
Trade receivables, net of allowances of $0.1 and $0.9 million at March 31, 2017 and December 31, 2016	536.1	673.2
Inventories	75.5	137.7
Assets from risk management activities	23.9	16.8
Other current assets	26.9	31.5
Total current assets	734.1	927.2
Property, plant and equipment	12,950.2	12,511.9
Accumulated depreciation	(2,986.8)	(2,821.0)
Property, plant and equipment, net	9,963.4	9,690.9
Intangible assets, net	2,238.8	1,654.0
Goodwill, net	369.0	210.0
Long-term assets from risk management activities	21.6	5.1
Investments in unconsolidated affiliates	227.0	240.8
Other long-term assets	15.9	16.9
Total assets	13,569.8	12,744.9
Current liabilities:
Accounts payable and accrued liabilities	819.5	773.9
Accounts payable to Targa Resources Corp.	46.5	61.0
Liabilities from risk management activities	22.2	49.1
Current maturities of debt	534.9	275.0
Total current liabilities	1,423.1	1,159.0
Long-term debt	3,778.3	4,177.0
Long-term liabilities from risk management activities	7.9	26.1
Deferred income taxes, net	26.4	26.9
Other long-term liabilities	676.4	205.3
Contingencies (see Note 16)
Owners' equity:
Series A preferred limited partners (5,000,000 and 5,000,000 units issued and 5,000,000 and 5,000,000 outstanding as of March 31, 2017 and December 31, 2016)	120.6	120.6
Common limited partners (275,168,410 and 275,168,410 units issued and 275,168,410 and 275,168,410 outstanding as of March 31, 2017 and December 31, 2016)	6,360.9	5,939.9
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of March 31, 2017 and December 31, 2016)	805.3	796.7
Accumulated other comprehensive income (loss)	10.5	(61.8)
Partners' Capital	7,297.3	6,795.4
Noncontrolling interests in subsidiaries	360.4	355.2
Total owners' equity	7,657.7	7,150.6
Total liabilities and owners' equity	$ 13,569.8	$ 12,744.9

XML

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

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Sales of commodities	$ 1,858.1	$ 1,171.0
Fees from midstream services	254.5	271.4
Total revenues	2,112.6	1,442.4
Costs and expenses:
Product purchases	1,654.2	1,011.0
Operating expenses	151.9	132.0
Depreciation and amortization expense	191.1	193.5
General and administrative expense	45.5	43.4
Goodwill impairment	0.0	24.0
Other operating (income) expense	16.2	1.0
Income from operations	53.7	37.5
Other income (expense):
Interest expense, net	(58.6)	(46.9)
Equity earnings (loss)	(12.6)	(4.8)
Gain from financing activities	0.0	24.7
Other	(8.5)	(0.1)
Income (loss) before income taxes	(26.0)	10.4
Income tax (expense) benefit	4.7	0.2
Net income (loss)	(21.3)	10.6
Less: Net income attributable to noncontrolling interests	6.0	3.0
Net income (loss) attributable to Targa Resources Partners LP	(27.3)	7.6
Net income attributable to preferred limited partners	2.8	2.8
Net income (loss) attributable to general partner	(0.6)	14.7
Net income (loss) attributable to common limited partners	(29.5)	(9.9)
Net income (loss) attributable to Targa Resources Partners LP	$ (27.3)	$ 7.6

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income (loss)	$ (21.3)	$ 10.6
Other comprehensive income (loss):
Other comprehensive income (loss)	72.3	(17.5)
Comprehensive income (loss)	51.0	(6.9)
Less: Comprehensive income attributable to noncontrolling interests	6.0	3.0
Comprehensive income (loss) attributable to Targa Resources Partners LP	45.0	(9.9)
Commodity Contracts [Member]
Other comprehensive income (loss):
Settlements reclassified to revenues	6.1	(24.2)
Change in fair value	$ 66.2	$ 6.7

XML

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - USD ($) shares in Thousands, $ in Millions	Total	Limited Partner Preferred [Member]	Limited Partners Common [Member]	General Partner Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Units [Member]	Non-controlling Interests [Member]
Balance at Dec. 31, 2015	$ 6,902.9	$ 120.6	$ 4,550.4	$ 1,735.3	$ 86.8	$ (10.3)	$ 420.1
Balance (in units) at Dec. 31, 2015		5,000	184,871	3,773		212
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	2.2	$ 0.0	$ 2.2	$ 0.0	0.0	$ 0.0	0.0
Compensation on equity grants (in units)		0	0	0		0
Distribution equivalent rights	(0.2)	$ 0.0	$ (0.2)	$ 0.0	0.0	$ 0.0	0.0
Issuance of common units under compensation program	0.0	$ 0.0	$ 0.0	$ 0.0	0.0	$ 0.0	0.0
Issuance of common units under compensation program (in units)		0	30	0		0
Units tendered for tax withholding obligations	(0.1)	$ 0.0	$ 0.0	$ 0.0	0.0	$ (0.1)	0.0
Units tendered for tax withholding obligations (in units)		0	(1)	0		1
Cancellation of treasury units			$ (10.2)	$ (0.2)		$ 10.4
Cancellation of treasury units (in units)		0	0	0		(213)
Contributions from Targa Resources Corp.	801.0	$ 0.0	$ 785.0	$ 16.0	0.0	$ 0.0	0.0
Contributions from Targa Resources Corp. (in units)		0	45,103	921		0
Distributions to noncontrolling interests	(2.1)	$ 0.0	$ 0.0	$ 0.0	0.0	$ 0.0	(2.1)
Contributions from noncontrolling interests	6.0	0.0	0.0	0.0	0.0	0.0	6.0
Other comprehensive income (loss)	(17.5)	0.0	0.0	0.0	(17.5)	0.0	0.0
Net income (loss)	10.6	2.8	(9.9)	14.7	0.0	0.0	3.0
Distributions	(203.2)	(2.8)	(152.5)	(47.9)	0.0	0.0	0.0
Balance at Mar. 31, 2016	7,499.6	$ 120.6	$ 5,164.8	$ 1,717.9	69.3	$ 0.0	427.0
Balance (in units) at Mar. 31, 2016		5,000	230,003	4,694		0
Balance at Dec. 31, 2016	7,150.6	$ 120.6	$ 5,939.9	$ 796.7	(61.8)	$ 0.0	355.2
Balance (in units) at Dec. 31, 2016		5,000	275,168	5,629		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Targa Resources Corp.	655.0	$ 0.0	$ 641.9	$ 13.1	0.0	$ 0.0	0.0
Contributions from Targa Resources Corp. (in units)		0	0	0		0
Distributions to noncontrolling interests	(9.7)	$ 0.0	$ 0.0	$ 0.0	0.0	$ 0.0	(9.7)
Contributions from noncontrolling interests	8.9	0.0	0.0	0.0	0.0	0.0	8.9
Other comprehensive income (loss)	72.3	0.0	0.0	0.0	72.3	0.0	0.0
Net income (loss)	(21.3)	2.8	(29.5)	(0.6)	0.0	0.0	6.0
Distributions	(198.1)	(2.8)	(191.4)	(3.9)	0.0	0.0	0.0
Balance at Mar. 31, 2017	$ 7,657.7	$ 120.6	$ 6,360.9	$ 805.3	$ 10.5	$ 0.0	$ 360.4
Balance (in units) at Mar. 31, 2017		5,000	275,168	5,629		0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities
Net income (loss)		$ (21,300,000)	$ 10,600,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		2,400,000	3,400,000
Compensation on equity grants		0	2,200,000
Depreciation and amortization expense		191,100,000	193,500,000
Goodwill impairment		0	24,000,000
Accretion of asset retirement obligations		1,300,000	1,100,000
Increase (decrease) in redemption value of mandatorily redeemable preferred interests		2,500,000	(18,500,000)
Deferred income tax expense (benefit)		(500,000)	(6,600,000)
Equity (earnings) loss of unconsolidated affiliates		12,600,000	4,800,000
Distributions of earnings received from unconsolidated affiliates		2,700,000	0
Risk management activities		8,500,000	4,400,000
(Gain) loss on sale or disposition of assets	[1]	16,100,000	900,000
(Gain) loss from financing activities		0	(24,700,000)
Change in contingent considerations		3,300,000	0
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		140,600,000	99,300,000
Inventories		53,700,000	62,100,000
Accounts payable and other liabilities		(99,800,000)	(114,500,000)
Net cash provided by operating activities		313,200,000	242,000,000
Cash flows from investing activities
Outlays for property, plant and equipment		(144,200,000)	(190,100,000)
Outlays for business acquisition, net of cash acquired		(480,800,000)	0
Investments in unconsolidated affiliates		(500,000)	0
Return of capital from unconsolidated affiliates		0	3,400,000
Other, net		0	(1,300,000)
Net cash used in investing activities		(625,500,000)	(188,000,000)
Debt obligations:
Proceeds from borrowings under credit facility		480,000,000	425,000,000
Repayments of credit facility		(630,000,000)	(705,000,000)
Proceeds from borrowings under accounts receivable securitization facility		75,000,000	5,700,000
Repayments of accounts receivable securitization facility		(65,000,000)	(75,000,000)
Redemption of senior notes		0	(330,600,000)
Costs incurred in connection with financing arrangements		(100,000)	(7,500,000)
Repurchase of common units under compensation plans		0	(100,000)
Contributions from general partner		13,100,000	16,000,000
Contributions from TRC		641,900,000	785,000,000
Contributions from noncontrolling interests		8,900,000	6,000,000
Distributions to noncontrolling interests		(9,700,000)	(2,100,000)
Distributions to unitholders		(198,100,000)	(203,200,000)
Payments of distribution equivalent rights		0	(300,000)
Net cash provided by (used in) financing activities		316,000,000	(86,100,000)
Net change in cash and cash equivalents		3,700,000	(32,100,000)
Cash and cash equivalents, beginning of period		68,000,000	135,400,000
Cash and cash equivalents, end of period		$ 71,700,000	$ 103,300,000

[1] Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale

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Organization and Operations

3 Months Ended

Mar. 31, 2017

Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract]

Organization and Operations

Note 1 — Organization and Operations

Our Organization

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transactions, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

Our Operations

We are engaged in the business of:

• gathering, compressing, treating, processing and selling natural gas;

• storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;

• gathering, storing and terminaling 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.

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Basis of Presentation

3 Months Ended

Mar. 31, 2017

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Basis of Presentation

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

The unaudited consolidated financial statements for the three months ended March 31, 2017 and 2016 include all adjustments that we believe are necessary for a fair statement of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

Our financial results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year.

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Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Significant Accounting Policies

Note 3 — Significant Accounting Policies

Accounting Policy Updates

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. There were no significant updates or revisions to our policies during the three months ended March 31, 2017, except as noted below.

Recent Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

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). These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Recognition of Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We are currently evaluating the effects of such amendments.

Goodwill Impairment

In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary.

Other Income

In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. The amendment also impacts the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendment on our consolidated financial statements. 

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Business Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2017

Business Combinations [Abstract]

Business Acquisitions and Divestitures

Note 4 – Business Acquisitions and Divestitures

2017 Acquisition

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 will pay $90.0 million within 90 days of closing (collectively, the “initial purchase price”). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.

New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.

New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017 and we expect that New Midland’s gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

The acquired businesses contributed revenues of $8.1 million and a net loss of $2.6 million to us for the period from March 1, 2017 to March 31, 2017, and are reported in our Gathering and Processing segment. As of March 31, 2017, we had incurred $5.1 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the three months ended March 31, 2017.

Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations

The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

	March 31, 2017			March 31, 2016
	Pro Forma			Pro Forma
Revenues	$	2,126.7		$	1,445.0
Net income (loss)		(22.7	)		(7.5	)

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:

• Reflect the amortization expense resulting from the preliminary estimate of the fair value of intangible assets recognized as part of the Permian Acquisition. For the purposes of preparing the pro forma adjustments we have assumed a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations.

• Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the preliminary estimate of the fair value of property, plant and equipment acquired.

• Exclude $5.1 million of acquisition-related costs incurred as of March 31, 2017 from pro forma net income for the three months ended March 31, 2017. Pro forma net income for the three months ended March 31, 2016 was adjusted to include those charges.

The following table summarizes the consideration transferred to acquire New Delaware and New Midland:

Fair Value of Consideration Transferred:
Cash paid, net of cash acquired (1)	$	480.8
Purchase consideration payable (2)		90.0
Contingent consideration		461.6
Total	$	1,032.4

(1) Net of cash acquired of $3.3 million.

(2) The payable will be settled in cash within 90 days from March 1, 2017.

We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the completion of the valuation and other post-closing adjustments. These and other estimates are subject to change as additional information becomes available and is assessed by us, and agreement is reached on the respective final settlement statements. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Fair value determination:	March 1, 2017
Trade and other current receivables, net	$	6.5
Other current assets		0.6
Property, plant and equipment		255.4
Intangible assets		625.6
Current liabilities		(14.3	)
Other long-term liabilities		(0.4	)
Total identifiable net assets		873.4
Goodwill		159.0
Total fair value of consideration transferred	$	1,032.4

Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value of net assets acquired was approximately $159.0 million, which was recorded as goodwill. As of March 31, 2017, this determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments. As a result, goodwill is also preliminary. The preliminary goodwill is attributable to expected operational and capital synergies. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.

The preliminary fair value of assets acquired included trade receivables of $6.5 million, all of which was expected to be collectible.

The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

Contingent Consideration

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. During the three months ended March 31, 2017, we recognized $3.2 million as Other expense related to the change in fair value of the contingent consideration. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.

2017 Divestiture

Sale of Venice Gathering System, L.L.C.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

The sale of VGS closed on April 4, 2017, and as a result, we recognized a loss of $16.1 million in our Consolidated Statements of Operations as part of Other operating (income) expense to impair our basis in the VGS assets to its fair value.

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Inventories

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Inventories

Note 5 — Inventories

	March 31, 2017		December 31, 2016
Commodities	$	65.1	$	126.9
Materials and supplies		10.4		10.8
	$	75.5	$	137.7

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Property, Plant and Equipment and Intangible Assets

3 Months Ended

Mar. 31, 2017

Property Plant And Equipment And Intangible Assets [Abstract]

Property, Plant and Equipment and Intangible Assets

Note 6 — Property, Plant and Equipment and Intangible Assets

Property, Plant and Equipment

	March 31, 2017			December 31, 2016			Estimated Useful Lives (In Years)
Gathering systems	$	6,777.7		$	6,626.9		5 to 20
Processing and fractionation facilities		3,500.4			3,383.6		5 to 25
Terminaling and storage facilities		1,231.7			1,205.0		5 to 25
Transportation assets		427.9			451.4		10 to 25
Other property, plant and equipment		280.4			274.0		3 to 25
Land		121.5			121.2		—
Construction in progress		610.6			449.8		—
Property, plant and equipment		12,950.2			12,511.9
Accumulated depreciation		(2,986.8	)		(2,821.0	)
Property, plant and equipment, net	$	9,963.4		$	9,690.9
Intangible assets	$	2,662.2		$	2,036.6		15 to 20
Accumulated amortization		(423.4	)		(382.6	)
Intangible assets, net	$	2,238.8		$	1,654.0

Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.

The intangible assets acquired in the Permian Acquisition were recorded at a preliminary fair value of $625.6 million pending completion of final valuations. For the purposes of preparing the accompanying financial statements (which include one month of amortization of these intangible assets), we are amortizing these intangible assets over a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations over the upcoming months.

The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.

The estimated annual amortization expense for intangible assets, including the provisional Permian valuations and straight-line treatment is approximately $184.2 million, $177.4 million, $166.4 million, $154.2 million and $144.3 million for each of the years 2017 through 2021.

The changes in our intangible assets are as follows:

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		625.6
Amortization		(40.8	)
Balance at March 31, 2017	$	2,238.8

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Goodwill

3 Months Ended

Mar. 31, 2017

Goodwill And Intangible Assets Disclosure [Abstract]

Goodwill

Note 7 – Goodwill

As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million on our Consolidated Statement of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.

Changes in the net book value of our goodwill are as follows:

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017 (preliminary valuation)		—		—		159.0		159.0
Balance at March 31, 2017, net	$	174.7	$	35.3	$	159.0	$	369.0

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Investments in Unconsolidated Affiliates

3 Months Ended

Mar. 31, 2017

Equity Method Investments And Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Note 8 – Investments in Unconsolidated Affiliates

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with the joint interest owners, which cover their costs of operations (excluding depreciation and amortization). The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments and our share of any operating expenses incurred by the T2 Joint Ventures.

The following table shows the activity related to our investments in unconsolidated affiliates:

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	240.8
Equity earnings (loss)		3.7			(1.1	)		(2.7	)		(12.5	)		(12.6	)
Cash distributions (1)		(2.7	)		—			—			—			(2.7	)
Contributions for expansion projects (2)		—			0.3			1.1			0.1			1.5
Balance at March 31, 2017	$	47.1		$	57.8		$	117.0		$	5.1		$	227.0

(1) During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.

(2)     Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

Our equity loss for the three months ended March 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment has occurred that is other than temporary. As a result of this evaluation, we have recorded an impairment loss of approximately $12.0 million, which represents our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as the impairment of the unamortized excess fair value resulting from the Atlas mergers.

The carrying values of the T2 gathering joint ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of March 31, 2017, $30.1 million of unamortized excess fair value over the T2 Joint Ventures capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20 year useful lives of the underlying assets.

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Accounts Payable and Accrued Liabilities

3 Months Ended

Mar. 31, 2017

Payables And Accruals [Abstract]

Accounts Payable and Accrued Liabilities

Note 9 — Accounts Payable and Accrued Liabilities

	March 31, 2017		December 31, 2016
Commodities	$	511.9	$	574.5
Other goods and services		120.7		113.4
Purchase consideration payable		90.0		-
Interest		51.5		52.2
Income and other taxes		22.5		19.1
Other		22.9		14.7
	$	819.5	$	773.9

Accounts payable and accrued liabilities includes $27.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2017 and December 31, 2016.

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Debt Obligations

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Debt Obligations

Note 10 — Debt Obligations

	March 31, 2017			December 31, 2016
Current:
Accounts receivable securitization facility, due December 2017	$	285.0		$	275.0
Senior unsecured notes, 5% fixed rate, due January 2018		250.5			—
		535.5			275.0
Debt issuance costs, net of amortization		(0.6	)		—
Current maturities of debt		534.9			275.0
Long-term:
Senior secured revolving credit facility, variable rate, due October 2020 (1)		—			150.0
Senior unsecured notes:
5% fixed rate, due January 2018		—			250.5
4⅛% fixed rate, due November 2019		749.4			749.4
6⅜% fixed rate, due August 2022		278.7			278.7
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		580.1			580.1
5⅛% fixed rate, due February 2025		500.0			500.0
5⅜% fixed rate, due February 2027		500.0			500.0
TPL notes, 4¾% fixed rate, due November 2021 (2)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (2)		48.1			48.1
Unamortized premium		0.5			0.5
		3,806.8			4,207.3
Debt issuance costs, net of amortization		(28.5	)		(30.3	)
Long-term debt		3,778.3			4,177.0
Total debt obligations	$	4,313.2		$	4,452.0
Irrevocable standby letters of credit outstanding	$	15.8		$	13.2

(1) As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

(2) Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2017:

	Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
TRP Revolver	3.0% - 5.3%			3.2%
Accounts receivable securitization facility		1.8%		1.8%

Compliance with Debt Covenants

As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements.

Securitization Facility

On February 23, 2017, we amended the accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million.  As of March 31, 2017, there was $285.0 million outstanding under the Securitization Facility.

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Other Long-term Liabilities

3 Months Ended

Mar. 31, 2017

Other Liabilities Noncurrent [Abstract]

Other Long-term Liabilities

Note 11 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following obligations:

	March 31, 2017		December 31, 2016
Asset retirement obligations	$	67.5	$	64.1
Mandatorily redeemable preferred interests		71.9		68.5
Deferred revenue		69.0		69.8
Permian Acquisition contingent consideration		464.8		-
Other liabilities		3.2		2.9
Total long-term liabilities	$	676.4	$	205.3

Asset Retirement Obligations

Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:

Balance at December 31, 2016	$	64.1
Additions (1)		0.4
Change in cash flow estimate		1.7
Accretion expense		1.3
Balance at March 31, 2017	$	67.5

_____________________________________________________________________________________________________________________________________________________________

(1) Amount reflects AROs assumed from the Permian Acquisition

Mandatorily Redeemable Preferred Interests

Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.

For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of March 31, 2017.

The following table shows the changes attributable to mandatorily redeemable preferred interests:

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		0.9
Change in estimated redemption value included in interest expense		2.5
Balance at March 31, 2017	$	71.9

Deferred Revenue

We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. Subsequent annual payments of $43.0 million (subject to an annual inflation factor) will be received through 2022. The deferred revenue will be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 and continuing through 2025.

Deferred revenue also includes consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement.  Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.

Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.

The following table shows the components of deferred revenue:

	March 31, 2017		December 31, 2016
Splitter agreement	$	43.0	$	43.0
Gas contract amendment		19.3		19.7
Other deferred revenue		6.7		7.1
Total deferred revenue	$	69.0	$	69.8

The following table shows the changes in deferred revenue:

Balance at December 31, 2016	$	69.8
Additions		-
Revenue recognized		(0.8	)
Balance at March 31, 2017	$	69.0

Contingent Consideration

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The first potential earn-out payment would occur in May 2018. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. For the one month ended March 31, 2017, we had an increase in the fair value of this liability of $3.2 million, bringing the Permian Acquisition contingent consideration to $464.8 million as of March 31, 2017. See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology.

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Partnership Units and Related Matters

3 Months Ended

Mar. 31, 2017

Partners Capital [Abstract]

Partnership Units and Related Matters

Note 12 — Partnership Units and Related Matters

Distributions

As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations.

The following details the distributions declared or paid by us during the three months ended March 31, 2017:

Three Months	Date Paid		Total			Distributionsto TargaResources
Ended	Or to Be Paid		Distributions			Corp.
March 31, 2017	May 11, 2017	$		209.6	$		206.8
December 31, 2016	February 10, 2017			198.1			195.3

Contributions

Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions to us, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. During three months ended March 31, 2017, TRC made total capital contributions to us of $655.0 million.     

Preferred Units

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit.   The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

Distributions on our Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

We paid $2.8 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three months ended March 31, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements.

Subsequent Event

In April 2017, the board of directors of 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, 2017.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Note 13 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of less than $0.1 million for the three months ended March 31, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the three months ended March 31, 2017.

We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues. 

At March 31, 2017, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2017		2018		2019
Natural Gas	Swaps	MMBtu/d		141,960		100,500		61,383
Natural Gas	Basis Swaps	MMBtu/d		95,963		1,103		-
Natural Gas	Futures	MMBtu/d		-		1,103		-
Natural Gas	Options	MMBtu/d		22,900		9,486		-
NGL	Swaps	Bbl/d		14,143		6,658		5,339
NGL	Futures	Bbl/d		5,702		1,288		-
NGL	Options	Bbl/d		1,647		1,676		-
Condensate	Swaps	Bbl/d		2,690		2,190		1,063
Condensate	Options	Bbl/d		1,380		691		590

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of March 31, 2017				Fair Value as of December 31, 2016
	Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	23.6	$	20.8	$	16.7	$	48.6
	Long-term		21.6		7.9		5.1		26.1
Total derivatives designated as hedging instruments		$	45.2	$	28.7	$	21.8	$	74.7
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.3	$	1.4	$	0.1	$	0.5
Total derivatives not designated as hedging instruments		$	0.3	$	1.4	$	0.1	$	0.5
Total current position		$	23.9	$	22.2	$	16.8	$	49.1
Total long-term position			21.6		7.9		5.1		26.1
Total derivatives		$	45.5	$	30.1	$	21.9	$	75.2

The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation							Pro forma net presentation
March 31, 2017		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	23.8	$	(20.8	)	$	0.1	$	10.8	$	(7.7	)
	Counterparties without offsetting positions - assets		0.1		-			-		0.1		-
	Counterparties without offsetting positions - liabilities		-		(1.4	)		-		-		(1.4	)
			23.9		(22.2	)		0.1		10.9		(9.1	)
Long Term Position
	Counterparties with offsetting positions or collateral		21.3		(6.6	)		-		16.7		(2.0	)
	Counterparties without offsetting positions - assets		0.3		-			-		0.3		-
	Counterparties without offsetting positions - liabilities		-		(1.3	)		-		-		(1.3	)
			21.6		(7.9	)		-		17.0		(3.3	)
Total Derivatives
	Counterparties with offsetting positions or collateral		45.1		(27.4	)		0.1		27.5		(9.7	)
	Counterparties without offsetting positions - assets		0.4		-			-		0.4		-
	Counterparties without offsetting positions - liabilities		-		(2.7	)		-		-		(2.7	)
		$	45.5	$	(30.1	)	$	0.1	$	27.9	$	(12.4	)
		Gross Presentation							Pro forma net presentation
December 31, 2016		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0	$	5.7	$	(28.0	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(3.0	)		-		-		(3.0	)
			16.8		(49.1	)		7.0		5.7		(31.0	)
Long Term Position
	Counterparties with offsetting positions or collateral		5.1		(18.7	)		-		-		(13.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(7.4	)		-		-		(7.4	)
			5.1		(26.1	)		-		-		(21.0	)
Total Derivatives
	Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0		5.7		(41.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(10.4	)		-		-		(10.4	)
		$	21.9	$	(75.2	)	$	7.0	$	5.7	$	(52.0	)

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of 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 $15.4 million as of March 31, 2017. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended March 31,
Hedging Relationships	2017		2016
Commodity contracts	$	66.2	$	6.7

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended March 31,
Location of Gain (Loss)	2017			2016
Revenues	$	(6.1	)	$	24.2

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2017			2016
Commodity contracts	Revenue	$	(0.8	)	$	1.8

Based on valuations as of March 31, 2017, we expect to reclassify commodity hedge related deferred gains of $10.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $2.6 million of losses to be reclassified over the next twelve months.

See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 14 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2017, a net asset position of $15.4 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $47.5 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $79.0 million, ignoring an adjustment for counterparty credit risk.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

• The 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 in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

		March 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)		$	37.7		$	37.7		$	—		$	35.7		$	2.0
Liabilities from commodity derivative contracts (1)			22.1			22.1			—			20.8			1.3
Permian Acquisition contingent consideration (2)			464.8			464.8			—			—			464.8
TPL contingent consideration (3)			2.7			2.7			—			—			2.7
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			71.7			71.7			—			—			—
TRP Revolver			—			—			—			—			—
Senior unsecured notes			4,057.3			4,169.1			—			4,169.1			—
Accounts receivable securitization facility			285.0			285.0			—			285.0			—
	December 31, 2016
				Fair Value
		Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)		$	21.0		$	21.0		$	—		$	19.6		$	1.4
Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9
TPL contingent consideration (3)			2.6			2.6			—			—			2.6
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			68.0			68.0			—			—			—
TRP Revolver			150.0			150.0			—			150.0			—
Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—
Accounts receivable securitization facility			275.0			275.0			—			275.0			—

(1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2) We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures.

(3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.

Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

As of March 31, 2017, we had 17 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

The fair value of the Permian Acquisition contingent consideration was determined using a Monte-Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate.  The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) on the Consolidated Statements of Operations.

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability
Balance, December 31, 2016		$	(3.6	)	$	(2.6	)
	Change in fair value of TPL contingent consideration		-			(0.1	)
	Fair value of Permian Acquisition contingent consideration (1)		-			(464.8	)
	New Level 3 derivative instruments		(0.1	)		-
	Transfers out of Level 3 (2)		1.6			-
	Settlements included in Revenue		0.2			-
	Unrealized gain/(loss) included in OCI		2.6			-
Balance, March 31, 2017		$	0.7		$	(467.5	)

(1) Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

(2) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

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Related Party Transactions - Targa

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions - Targa

Note 15 — Related Party Transactions - Targa

Relationship with Targa

We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.

The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.

	Three Months Ended March 31,
	2017		2016
Targa billings of payroll and related costs included in operating expense	$	47.0	$	40.2
Targa allocation of general and administrative expense		42.0		39.9
Cash distributions to Targa based on IDR, GP and common unit ownership (1)		195.3		61.4
Cash contributions from Targa related to limited partner ownership (2)		641.9		785.0
Cash contributions from Targa to maintain its 2% general partner ownership		13.1		16.0

_______________________

(1) As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on GP and common unit ownership.

(2) The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partnership and 2% to GP. See Note 12 – Partnership Units and Related Matters.

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Contingencies

3 Months Ended

Mar. 31, 2017

Loss Contingency [Abstract]

Contingencies

Note 16 – Contingencies

Legal Proceedings

Environmental Proceedings

On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014.  The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. On January 31, 2017, Targa Midstream Services LLC executed a settlement agreement with the New Mexico Environment Department which resolved the matter for a civil penalty in the amount of $29,223.

We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

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Other Operating (Income) Expense

3 Months Ended

Mar. 31, 2017

Other Income And Expenses [Abstract]

Other Operating (Income) Expense

Note 17 – Other Operating (Income) Expense

Other operating (income) expense is comprised of the following:

	Three Months Ended March 31,
	2017		2016
(Gain) loss on sale or disposal of assets (1)	$	16.1	$	0.9
Miscellaneous business tax		0.1		0.1
	$	16.2	$	1.0

(1) Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Note 18 — Supplemental Cash Flow Information

		Three Months Ended March 31,
		2017				2016
Cash:
Interest paid, net of capitalized interest (1)	$		53.5		$		77.3
Income taxes paid, net of refunds			(0.1	)			1.1
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$		8.3		$		16.9
Impact of capital expenditure accruals on property, plant and equipment			30.0				13.7
Transfers from materials and supplies inventory to property, plant and equipment			0.4				0.5
Contribution of property, plant and equipment to investment in unconsolidated affiliates.			1.0				—
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			1.7				(9.1	)
Non-cash balance sheet movements related to the Permian Acquisition:
Contingent consideration recorded at the acquisition date	$		461.6		$		—
Purchase consideration payable recorded for the Permian Acquisition			90.0				—
Non-cash financing activities:
Cancellation of treasury units	$		—		$		(10.2	)
Accrued distributions on unvested equity awards under share    compensation arrangements			—				0.2

_____________

(1) Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

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Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Segment Information

Note 19 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas; Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2017
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	166.7	$	1,692.4	$	(1.0	)	$	—		$	1,858.1
Fees from midstream    services		118.2		136.3		—			—			254.5
		284.9		1,828.7		(1.0	)		—			2,112.6
Intersegment revenues
Sales of commodities		713.0		75.4		—			(788.4	)		—
Fees from midstream    services		1.9		7.0		—			(8.9	)		—
		714.9		82.4		—			(797.3	)		—
Revenues	$	999.8	$	1,911.1	$	(1.0	)	$	(797.3	)	$	2,112.6
Operating margin	$	177.4	$	130.1	$	(1.0	)	$	—		$	306.5
Other financial information:
Total assets (1)	$	10,780.4	$	2,687.2	$	44.8		$	57.4		$	13,569.8
Goodwill	$	369.0	$	—	$	—		$	—		$	369.0
Capital expenditures	$	139.2	$	34.6	$	—		$	0.8		$	174.6

(1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

	Three Months Ended March 31, 2016
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	110.3	$	1,033.9	$	26.8	$	—		$	1,171.0
Fees from midstream    services		115.8		155.6		—		—			271.4
		226.1		1,189.5		26.8		—			1,442.4
Intersegment revenues
Sales of commodities		412.6		47.3		—		(459.9	)		—
Fees from midstream    services		2.1		4.1		—		(6.2	)		—
		414.7		51.4		—		(466.1	)		—
Revenues	$	640.8	$	1,240.9	$	26.8	$	(466.1	)	$	1,442.4
Operating margin	$	115.6	$	157.0	$	26.8	$	—		$	299.4
Other financial information:
Total assets (1)	$	10,219.0	$	2,501.0	$	105.7	$	42.9		$	12,868.6
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0
Capital expenditures	$	103.0	$	73.1	$	—	$	0.8		$	176.9

(1) Corporate assets at the segment level 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,
	2017			2016
Sales of commodities:
Natural gas	$	480.9		$	326.9
NGL		1,314.9			785.8
Condensate		43.6			22.2
Petroleum products		19.8			9.6
Derivative activities		(1.1	)		26.5
		1,858.1			1,171.0
Fees from midstream services:
Fractionating and treating		31.0			30.2
Storage, terminaling, transportation and export		99.7			118.4
Gathering and processing		107.7			105.0
Other		16.1			17.8
		254.5			271.4
Total revenues	$	2,112.6		$	1,442.4

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

	Three Months Ended March 31,
	2017			2016
Reconciliation of operating margin to net income (loss):
Operating margin	$	306.5		$	299.4
Depreciation and amortization expenses		(191.1	)		(193.5	)
General and administrative expenses		(45.5	)		(43.4	)
Goodwill impairment		-			(24.0	)
Interest expense, net		(58.6	)		(46.9	)
Other, net		(37.3	)		18.8
Income tax (expense) benefit		4.7			0.2
Net income (loss)	$	(21.3	)	$	10.6

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Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Accounting Policy Updates

Accounting Policy Updates

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. There were no significant updates or revisions to our policies during the three months ended March 31, 2017, except as noted below.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

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). These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Recognition of Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We are currently evaluating the effects of such amendments.

Goodwill Impairment

In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary.

Other Income

In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. The amendment also impacts the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendment on our consolidated financial statements. 

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Business Acquisitions and Divestitures (Tables)

3 Months Ended

Mar. 31, 2017

Business Combinations [Abstract]

Pro Forma Consolidated Information of Operations

The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

	March 31, 2017			March 31, 2016
	Pro Forma			Pro Forma
Revenues	$	2,126.7		$	1,445.0
Net income (loss)		(22.7	)		(7.5	)

Consideration Transferred to Acquire Permian Delaware Assets and Permian Midland Assets

The following table summarizes the consideration transferred to acquire New Delaware and New Midland:

Fair Value of Consideration Transferred:
Cash paid, net of cash acquired (1)	$	480.8
Purchase consideration payable (2)		90.0
Contingent consideration		461.6
Total	$	1,032.4

(1) Net of cash acquired of $3.3 million.

(2) The payable will be settled in cash within 90 days from March 1, 2017.

Fair Value of the Assets and Liabilities Assumed at Acquisition Date

The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Fair value determination:	March 1, 2017
Trade and other current receivables, net	$	6.5
Other current assets		0.6
Property, plant and equipment		255.4
Intangible assets		625.6
Current liabilities		(14.3	)
Other long-term liabilities		(0.4	)
Total identifiable net assets		873.4
Goodwill		159.0
Total fair value of consideration transferred	$	1,032.4

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Inventories (Tables)

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Components of Inventories

	March 31, 2017		December 31, 2016
Commodities	$	65.1	$	126.9
Materials and supplies		10.4		10.8
	$	75.5	$	137.7

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Property, Plant and Equipment and Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2017

Property Plant And Equipment And Intangible Assets [Abstract]

Property, Plant and Equipment and Intangible Assets

	March 31, 2017			December 31, 2016			Estimated Useful Lives (In Years)
Gathering systems	$	6,777.7		$	6,626.9		5 to 20
Processing and fractionation facilities		3,500.4			3,383.6		5 to 25
Terminaling and storage facilities		1,231.7			1,205.0		5 to 25
Transportation assets		427.9			451.4		10 to 25
Other property, plant and equipment		280.4			274.0		3 to 25
Land		121.5			121.2		—
Construction in progress		610.6			449.8		—
Property, plant and equipment		12,950.2			12,511.9
Accumulated depreciation		(2,986.8	)		(2,821.0	)
Property, plant and equipment, net	$	9,963.4		$	9,690.9
Intangible assets	$	2,662.2		$	2,036.6		15 to 20
Accumulated amortization		(423.4	)		(382.6	)
Intangible assets, net	$	2,238.8		$	1,654.0

Schedule of Changes in Intangible Assets

The changes in our intangible assets are as follows:

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		625.6
Amortization		(40.8	)
Balance at March 31, 2017	$	2,238.8

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Goodwill (Tables)

3 Months Ended

Mar. 31, 2017

Goodwill And Intangible Assets Disclosure [Abstract]

Changes in Net Book Value of Goodwill

Changes in the net book value of our goodwill are as follows:

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017 (preliminary valuation)		—		—		159.0		159.0
Balance at March 31, 2017, net	$	174.7	$	35.3	$	159.0	$	369.0

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Investments in Unconsolidated Affiliates (Tables)

3 Months Ended

Mar. 31, 2017

Equity Method Investments And Joint Ventures [Abstract]

Activity Related to Partnership's Investment in Unconsolidated Affiliate

The following table shows the activity related to our investments in unconsolidated affiliates:

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	240.8
Equity earnings (loss)		3.7			(1.1	)		(2.7	)		(12.5	)		(12.6	)
Cash distributions (1)		(2.7	)		—			—			—			(2.7	)
Contributions for expansion projects (2)		—			0.3			1.1			0.1			1.5
Balance at March 31, 2017	$	47.1		$	57.8		$	117.0		$	5.1		$	227.0

(1) During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.

(2)     Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

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Accounts Payable and Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

Payables And Accruals [Abstract]

Schedule of Accounts Payable and Accrued Liabilities

	March 31, 2017		December 31, 2016
Commodities	$	511.9	$	574.5
Other goods and services		120.7		113.4
Purchase consideration payable		90.0		-
Interest		51.5		52.2
Income and other taxes		22.5		19.1
Other		22.9		14.7
	$	819.5	$	773.9

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Debt Obligations (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of Outstanding Debt

	March 31, 2017			December 31, 2016
Current:
Accounts receivable securitization facility, due December 2017	$	285.0		$	275.0
Senior unsecured notes, 5% fixed rate, due January 2018		250.5			—
		535.5			275.0
Debt issuance costs, net of amortization		(0.6	)		—
Current maturities of debt		534.9			275.0
Long-term:
Senior secured revolving credit facility, variable rate, due October 2020 (1)		—			150.0
Senior unsecured notes:
5% fixed rate, due January 2018		—			250.5
4⅛% fixed rate, due November 2019		749.4			749.4
6⅜% fixed rate, due August 2022		278.7			278.7
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		580.1			580.1
5⅛% fixed rate, due February 2025		500.0			500.0
5⅜% fixed rate, due February 2027		500.0			500.0
TPL notes, 4¾% fixed rate, due November 2021 (2)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (2)		48.1			48.1
Unamortized premium		0.5			0.5
		3,806.8			4,207.3
Debt issuance costs, net of amortization		(28.5	)		(30.3	)
Long-term debt		3,778.3			4,177.0
Total debt obligations	$	4,313.2		$	4,452.0
Irrevocable standby letters of credit outstanding	$	15.8		$	13.2

(1) As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

(2) Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

Interest Rates Incurred on Variable-Rate Debt Obligations

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2017:

	Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
TRP Revolver	3.0% - 5.3%			3.2%
Accounts receivable securitization facility		1.8%		1.8%

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Other Long-term Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

Other Liabilities Noncurrent [Abstract]

Other Long-term Liabilities

Other long-term liabilities are comprised of the following obligations:

	March 31, 2017		December 31, 2016
Asset retirement obligations	$	67.5	$	64.1
Mandatorily redeemable preferred interests		71.9		68.5
Deferred revenue		69.0		69.8
Permian Acquisition contingent consideration		464.8		-
Other liabilities		3.2		2.9
Total long-term liabilities	$	676.4	$	205.3

Changes in Aggregate Asset Retirement Obligations

The changes in our ARO are as follows

Balance at December 31, 2016	$	64.1
Additions (1)		0.4
Change in cash flow estimate		1.7
Accretion expense		1.3
Balance at March 31, 2017	$	67.5

_____________________________________________________________________________________________________________________________________________________________

(1) Amount reflects AROs assumed from the Permian Acquisition

Schedule of Changes Attributable to Mandatorily Redeemable Preferred Interests

The following table shows the changes attributable to mandatorily redeemable preferred interests:

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		0.9
Change in estimated redemption value included in interest expense		2.5
Balance at March 31, 2017	$	71.9

Components of Deferred Revenue

The following table shows the components of deferred revenue:

	March 31, 2017		December 31, 2016
Splitter agreement	$	43.0	$	43.0
Gas contract amendment		19.3		19.7
Other deferred revenue		6.7		7.1
Total deferred revenue	$	69.0	$	69.8

Changes in Deferred Revenue

The following table shows the changes in deferred revenue:

Balance at December 31, 2016	$	69.8
Additions		-
Revenue recognized		(0.8	)
Balance at March 31, 2017	$	69.0

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Partnership Units and Related Matters (Tables)

3 Months Ended

Mar. 31, 2017

Partners Capital [Abstract]

Schedule of Distributions

The following details the distributions declared or paid by us during the three months ended March 31, 2017:

Three Months	Date Paid		Total			Distributionsto TargaResources
Ended	Or to Be Paid		Distributions			Corp.
March 31, 2017	May 11, 2017	$		209.6	$		206.8
December 31, 2016	February 10, 2017			198.1			195.3

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Notional Volume of Commodity Hedges

At March 31, 2017, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2017		2018		2019
Natural Gas	Swaps	MMBtu/d		141,960		100,500		61,383
Natural Gas	Basis Swaps	MMBtu/d		95,963		1,103		-
Natural Gas	Futures	MMBtu/d		-		1,103		-
Natural Gas	Options	MMBtu/d		22,900		9,486		-
NGL	Swaps	Bbl/d		14,143		6,658		5,339
NGL	Futures	Bbl/d		5,702		1,288		-
NGL	Options	Bbl/d		1,647		1,676		-
Condensate	Swaps	Bbl/d		2,690		2,190		1,063
Condensate	Options	Bbl/d		1,380		691		590

Fair Values of Derivative Instruments

The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of March 31, 2017				Fair Value as of December 31, 2016
	Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	23.6	$	20.8	$	16.7	$	48.6
	Long-term		21.6		7.9		5.1		26.1
Total derivatives designated as hedging instruments		$	45.2	$	28.7	$	21.8	$	74.7
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.3	$	1.4	$	0.1	$	0.5
Total derivatives not designated as hedging instruments		$	0.3	$	1.4	$	0.1	$	0.5
Total current position		$	23.9	$	22.2	$	16.8	$	49.1
Total long-term position			21.6		7.9		5.1		26.1
Total derivatives		$	45.5	$	30.1	$	21.9	$	75.2

Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet

The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation							Pro forma net presentation
March 31, 2017		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	23.8	$	(20.8	)	$	0.1	$	10.8	$	(7.7	)
	Counterparties without offsetting positions - assets		0.1		-			-		0.1		-
	Counterparties without offsetting positions - liabilities		-		(1.4	)		-		-		(1.4	)
			23.9		(22.2	)		0.1		10.9		(9.1	)
Long Term Position
	Counterparties with offsetting positions or collateral		21.3		(6.6	)		-		16.7		(2.0	)
	Counterparties without offsetting positions - assets		0.3		-			-		0.3		-
	Counterparties without offsetting positions - liabilities		-		(1.3	)		-		-		(1.3	)
			21.6		(7.9	)		-		17.0		(3.3	)
Total Derivatives
	Counterparties with offsetting positions or collateral		45.1		(27.4	)		0.1		27.5		(9.7	)
	Counterparties without offsetting positions - assets		0.4		-			-		0.4		-
	Counterparties without offsetting positions - liabilities		-		(2.7	)		-		-		(2.7	)
		$	45.5	$	(30.1	)	$	0.1	$	27.9	$	(12.4	)
		Gross Presentation							Pro forma net presentation
December 31, 2016		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0	$	5.7	$	(28.0	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(3.0	)		-		-		(3.0	)
			16.8		(49.1	)		7.0		5.7		(31.0	)
Long Term Position
	Counterparties with offsetting positions or collateral		5.1		(18.7	)		-		-		(13.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(7.4	)		-		-		(7.4	)
			5.1		(26.1	)		-		-		(21.0	)
Total Derivatives
	Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0		5.7		(41.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(10.4	)		-		-		(10.4	)
		$	21.9	$	(75.2	)	$	7.0	$	5.7	$	(52.0	)

Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue and Expense

The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended March 31,
Hedging Relationships	2017		2016
Commodity contracts	$	66.2	$	6.7

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended March 31,
Location of Gain (Loss)	2017			2016
Revenues	$	(6.1	)	$	24.2

Gain (Loss) Recognized in Income on Derivatives

The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2017			2016
Commodity contracts	Revenue	$	(0.8	)	$	1.8

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Breakdown by Fair Value Hierarchy Category for Financial Instruments Included in Consolidated Balance Sheets

The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

		March 31, 2017
					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)		$	37.7		$	37.7		$	—		$	35.7		$	2.0
Liabilities from commodity derivative contracts (1)			22.1			22.1			—			20.8			1.3
Permian Acquisition contingent consideration (2)			464.8			464.8			—			—			464.8
TPL contingent consideration (3)			2.7			2.7			—			—			2.7
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			71.7			71.7			—			—			—
TRP Revolver			—			—			—			—			—
Senior unsecured notes			4,057.3			4,169.1			—			4,169.1			—
Accounts receivable securitization facility			285.0			285.0			—			285.0			—
	December 31, 2016
				Fair Value
		Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)		$	21.0		$	21.0		$	—		$	19.6		$	1.4
Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9
TPL contingent consideration (3)			2.6			2.6			—			—			2.6
Financial Instruments Recorded on Our    Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			68.0			68.0			—			—			—
TRP Revolver			150.0			150.0			—			150.0			—
Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—
Accounts receivable securitization facility			275.0			275.0			—			275.0			—

(1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2) We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures.

(3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.

Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability
Balance, December 31, 2016		$	(3.6	)	$	(2.6	)
	Change in fair value of TPL contingent consideration		-			(0.1	)
	Fair value of Permian Acquisition contingent consideration (1)		-			(464.8	)
	New Level 3 derivative instruments		(0.1	)		-
	Transfers out of Level 3 (2)		1.6			-
	Settlements included in Revenue		0.2			-
	Unrealized gain/(loss) included in OCI		2.6			-
Balance, March 31, 2017		$	0.7		$	(467.5	)

(1) Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

(2) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

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Related Party Transactions - Targa (Tables)

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Summary of Transactions with Affiliates

The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.

	Three Months Ended March 31,
	2017		2016
Targa billings of payroll and related costs included in operating expense	$	47.0	$	40.2
Targa allocation of general and administrative expense		42.0		39.9
Cash distributions to Targa based on IDR, GP and common unit ownership (1)		195.3		61.4
Cash contributions from Targa related to limited partner ownership (2)		641.9		785.0
Cash contributions from Targa to maintain its 2% general partner ownership		13.1		16.0

_______________________

(1) As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on GP and common unit ownership.

(2) The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partnership and 2% to GP. See Note 12 – Partnership Units and Related Matters.

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Other Operating (Income) Expense (Tables)

3 Months Ended

Mar. 31, 2017

Other Income And Expenses [Abstract]

Other Operating (Income) Expense

Other operating (income) expense is comprised of the following:

	Three Months Ended March 31,
	2017		2016
(Gain) loss on sale or disposal of assets (1)	$	16.1	$	0.9
Miscellaneous business tax		0.1		0.1
	$	16.2	$	1.0

(1) Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

		Three Months Ended March 31,
		2017				2016
Cash:
Interest paid, net of capitalized interest (1)	$		53.5		$		77.3
Income taxes paid, net of refunds			(0.1	)			1.1
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$		8.3		$		16.9
Impact of capital expenditure accruals on property, plant and equipment			30.0				13.7
Transfers from materials and supplies inventory to property, plant and equipment			0.4				0.5
Contribution of property, plant and equipment to investment in unconsolidated affiliates.			1.0				—
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			1.7				(9.1	)
Non-cash balance sheet movements related to the Permian Acquisition:
Contingent consideration recorded at the acquisition date	$		461.6		$		—
Purchase consideration payable recorded for the Permian Acquisition			90.0				—
Non-cash financing activities:
Cancellation of treasury units	$		—		$		(10.2	)
Accrued distributions on unvested equity awards under share    compensation arrangements			—				0.2

_____________

(1) Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Information by Segment

Reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2017
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	166.7	$	1,692.4	$	(1.0	)	$	—		$	1,858.1
Fees from midstream    services		118.2		136.3		—			—			254.5
		284.9		1,828.7		(1.0	)		—			2,112.6
Intersegment revenues
Sales of commodities		713.0		75.4		—			(788.4	)		—
Fees from midstream    services		1.9		7.0		—			(8.9	)		—
		714.9		82.4		—			(797.3	)		—
Revenues	$	999.8	$	1,911.1	$	(1.0	)	$	(797.3	)	$	2,112.6
Operating margin	$	177.4	$	130.1	$	(1.0	)	$	—		$	306.5
Other financial information:
Total assets (1)	$	10,780.4	$	2,687.2	$	44.8		$	57.4		$	13,569.8
Goodwill	$	369.0	$	—	$	—		$	—		$	369.0
Capital expenditures	$	139.2	$	34.6	$	—		$	0.8		$	174.6

(1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

	Three Months Ended March 31, 2016
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	110.3	$	1,033.9	$	26.8	$	—		$	1,171.0
Fees from midstream    services		115.8		155.6		—		—			271.4
		226.1		1,189.5		26.8		—			1,442.4
Intersegment revenues
Sales of commodities		412.6		47.3		—		(459.9	)		—
Fees from midstream    services		2.1		4.1		—		(6.2	)		—
		414.7		51.4		—		(466.1	)		—
Revenues	$	640.8	$	1,240.9	$	26.8	$	(466.1	)	$	1,442.4
Operating margin	$	115.6	$	157.0	$	26.8	$	—		$	299.4
Other financial information:
Total assets (1)	$	10,219.0	$	2,501.0	$	105.7	$	42.9		$	12,868.6
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0
Capital expenditures	$	103.0	$	73.1	$	—	$	0.8		$	176.9

(1) Corporate assets at the segment level 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,
	2017			2016
Sales of commodities:
Natural gas	$	480.9		$	326.9
NGL		1,314.9			785.8
Condensate		43.6			22.2
Petroleum products		19.8			9.6
Derivative activities		(1.1	)		26.5
		1,858.1			1,171.0
Fees from midstream services:
Fractionating and treating		31.0			30.2
Storage, terminaling, transportation and export		99.7			118.4
Gathering and processing		107.7			105.0
Other		16.1			17.8
		254.5			271.4
Total revenues	$	2,112.6		$	1,442.4

Reconciliation of Operating Margin to Net Income (Loss)

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

	Three Months Ended March 31,
	2017			2016
Reconciliation of operating margin to net income (loss):
Operating margin	$	306.5		$	299.4
Depreciation and amortization expenses		(191.1	)		(193.5	)
General and administrative expenses		(45.5	)		(43.4	)
Goodwill impairment		-			(24.0	)
Interest expense, net		(58.6	)		(46.9	)
Other, net		(37.3	)		18.8
Income tax (expense) benefit		4.7			0.2
Net income (loss)	$	(21.3	)	$	10.6

XML

Organization and Operations (Details)		3 Months Ended
	Feb. 17, 2016 $ / shares	Mar. 31, 2017 shares	Dec. 31, 2016 shares
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items]
Conversion ratio in stock-for-unit transaction	0.62
Common stock, par value (in dollars per share) | $ / shares	$ 0.001
Series A Cumulative Redeemable Perpetual Preferred Units [Member]
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items]
Preferred units issued (in units) | shares		5,000,000	5,000,000
Preferred units dividend percentage		9.00%

XML

Business Acquisitions and Divestitures - Additional Information (Details)		1 Months Ended	3 Months Ended
	Mar. 01, 2017 USD ($) a MMcf bbl	Mar. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)
Permian Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Cash payments related to acquisition	$ 484,100,000
Acquired debt and all other assumed liabilities included purchase consideration	90,000,000
Revenues from acquired businesses		$ 8,100,000
Net loss from acquired businesses		$ (2,600,000)
Acquisition-related expenses			$ 5,100,000
Permian Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment	$ 935,000,000
New Delaware [Member]
Business Acquisition [Line Items]
Average weighted contract life	14 years
Gas processing capacity | MMcf	70
Crude gathering capacity | bbl	40,000
New Delaware [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering assets | a	145,000
New Midland [Member]
Business Acquisition [Line Items]
Average weighted contract life	13 years
Gas processing capacity | MMcf	10
Crude gathering capacity | bbl	40,000
New Midland [Member] | Minimum [Member]
Business Acquisition [Line Items]
Area of gas gathering and processing and crude gathering assets | a	105,000

XML

Business Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pro forma consolidated results of operations [Abstract]
Estimated useful life	20 years
Permian Acquisition [Member]
Pro forma consolidated results of operations [Abstract]
Revenues	$ 2,126.7	$ 1,445.0
Net income (loss)	$ (22.7)	$ (7.5)
Estimated useful life	15 years
Acquisition-related costs	$ 5.1

XML

Business Acquisitions and Divestitures - Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions			3 Months Ended
		Mar. 01, 2017	Mar. 31, 2017	Mar. 31, 2016
Fair Value of Consideration Transferred by Targa [Abstract]
Cash paid, net of cash acquired			$ 480.8	$ 0.0
Purchase consideration payable			90.0
Permian Acquisition [Member]
Fair Value of Consideration Transferred by Targa [Abstract]
Purchase consideration payable			$ 90.0
Total fair value of consideration transferred		$ 1,032.4
Targa Resources Corp [Member] | Permian Acquisition [Member]
Fair Value of Consideration Transferred by Targa [Abstract]
Cash paid, net of cash acquired	[1]	480.8
Purchase consideration payable	[2]	90.0
Contingent consideration		461.6
Total fair value of consideration transferred		$ 1,032.4

[1] Net of cash acquired of $3.3 million.

[2] The payable will be settled in cash within 90 days from March 1, 2017.

XML

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

XML

Business Acquisitions and Divestitures - Fair Value of the Assets and Liabilities Assumed at Acquisition Date (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 01, 2017	Dec. 31, 2016
Fair value determination [Abstract]
Goodwill	$ 369.0	$ 159.0	$ 210.0
Permian Acquisition [Member]
Fair value determination [Abstract]
Trade and other current receivables, net		6.5
Other current assets		0.6
Property, plant and equipment		255.4
Intangible assets		625.6
Current liabilities		(14.3)
Other long-term liabilities		(0.4)
Total identifiable net assets		873.4
Goodwill		159.0
Total fair value of consideration transferred		$ 1,032.4

XML

Business Acquisitions and Divestitures - Additional Information Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 01, 2017	Dec. 31, 2016
Fair value determination [Abstract]
Goodwill	$ 369.0	$ 159.0	$ 210.0
Measurement-period adjustments to preliminary acquisition date fair values [Abstract]
Trade receivables, preliminary fair value		$ 6.5

XML

Business Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - Permian Acquisition [Member] - USD ($)	1 Months Ended	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Mar. 01, 2017
Business Acquisition [Line Items]
Potential earn-out payments acquisition date preliminary fair value	$ 461,600,000	$ 461,600,000
Other expense related to change in fair value of contingent consideration	3,200,000	3,200,000
Maximum [Member]
Business Acquisition [Line Items]
Additional cash that may be paid based on potential earn-out payment			$ 935,000,000
Other Long-term Liabilities [Member]
Business Acquisition [Line Items]
Potential earn-out payments acquisition date preliminary fair value	$ 461,600,000	$ 461,600,000	$ 461,600,000

XML

Business Acquisitions and Divestitures - Additional Information 2017 Divestiture (Details) - USD ($) $ in Millions		3 Months Ended
	Apr. 04, 2017	Mar. 31, 2017
Venice Gathering System, L.L.C. [Member]
Business Acquisition [Line Items]
Loss from sale of divestiture of businesses		$ (16.1)
Venice Gathering System, L.L.C. [Member] | Disposal Group, Not Discontinued Operations [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Subsidiary ownership interest sale percentage	100.00%
Proceeds from divestiture of businesses	$ 0.4
Venice Energy Services Company, L.L.C. [Member]
Business Acquisition [Line Items]
Ownership interest		76.80%

XML

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

XML

Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 12,950.2	$ 12,511.9
Accumulated depreciation	(2,986.8)	(2,821.0)
Property, plant and equipment, net	9,963.4	9,690.9
Intangible assets	2,662.2	2,036.6
Accumulated amortization	(423.4)	(382.6)
Intangible assets, net	$ 2,238.8	1,654.0
Estimated useful life	20 years
Additions from acquisition	$ 625.6
Permian Acquisition [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	15 years
Badlands [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	20 years
Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	15 years
Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	20 years
Gathering Systems [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 6,777.7	6,626.9
Gathering Systems [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	5 years
Gathering Systems [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	20 years
Processing and Fractionation Facilities [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 3,500.4	3,383.6
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	25 years
Terminaling and Storage Facilities [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 1,231.7	1,205.0
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	$ 427.9	451.4
Transportation Assets [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	10 years
Transportation Assets [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful life	25 years
Other Property, Plant and Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 280.4	274.0
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	$ 121.5	121.2
Construction in Progress [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 610.6	$ 449.8

XML

Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) $ in Millions	Mar. 31, 2017 USD ($)
Estimated amortization expense for intangible assets [Abstract]
2017	$ 184.2
2018	177.4
2019	166.4
2020	154.2
2021	$ 144.3

XML

Property, Plant and Equipment and Intangible Assets, Schedule of Changes in Intangible Assets(Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Intangible Assets, net [Roll Forward]
Balance at December 31, 2016	$ 1,654.0
Additions from Permian Acquisition	625.6
Amortization	(40.8)
Balance at March 31, 2017	$ 2,238.8

XML

Goodwill (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill impairment	$ 0.0	$ 24.0

XML

Goodwill - Changes in Net Book Value of Goodwill (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Goodwill [Roll Forward]
Beginning balance	$ 210.0
Permian Acquisition, March 1, 2017 (preliminary valuation)	159.0
Ending balance	369.0
WestTX [Member]
Goodwill [Roll Forward]
Beginning balance	174.7
Ending balance	174.7
SouthTX [Member]
Goodwill [Roll Forward]
Beginning balance	35.3
Ending balance	35.3
Permian [Member]
Goodwill [Roll Forward]
Permian Acquisition, March 1, 2017 (preliminary valuation)	159.0
Ending balance	$ 159.0

XML

Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) 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	$ 30.1
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%
Impairment loss	$ 12.0

XML

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		$ 240.8
Equity earnings (loss)		(12.6)	$ (4.8)
Cash distributions	[1]	(2.7)
Contributions for expansion projects	[2]	1.5
Balance at end of period		227.0
Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		46.1
Equity earnings (loss)		3.7
Cash distributions	[1]	(2.7)
Contributions for expansion projects	[2]	0.0
Balance at end of period		47.1
T2 La Salle [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		58.6
Equity earnings (loss)		(1.1)
Cash distributions	[1]	0.0
Contributions for expansion projects	[2]	0.3
Balance at end of period		57.8
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		118.6
Equity earnings (loss)		(2.7)
Cash distributions	[1]	0.0
Contributions for expansion projects	[2]	1.1
Balance at end of period		117.0
T2 EF Cogen [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		17.5
Equity earnings (loss)		(12.5)
Cash distributions	[1]	0.0
Contributions for expansion projects	[2]	0.1
Balance at end of period		$ 5.1

[1] During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings.

[2] Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

XML

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

XML

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Components of accounts payable and accrued liabilities [Abstract]
Commodities	$ 511.9	$ 574.5
Other goods and services	120.7	113.4
Purchase consideration payable	90.0
Interest	51.5	52.2
Income and other taxes	22.5	19.1
Other	22.9	14.7
Accounts payable and accrued liabilities	$ 819.5	$ 773.9

XML

Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Outstanding checks	$ 27.2	$ 30.2

XML

Debt Obligations (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Current:
Current debt		$ 535.5	$ 275.0
Debt issuance costs, net of amortization		(0.6)
Current maturities of debt		534.9	275.0
Long-term [Abstract]
Long-term debt		3,778.3	4,177.0
Long-term debt including unamortized premium (discount)		3,806.8	4,207.3
Total debt obligations		4,313.2	4,452.0
Debt issuance costs, net of amortization		(28.5)	(30.3)
Irrevocable standby letters of credit outstanding		15.8	13.2
Senior Unsecured 5% Notes due January 2018 [Member]
Current:
Current unsecured debt		250.5
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]
Long-term [Abstract]
Long-term debt			250.5
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member]
Long-term [Abstract]
Long-term debt		749.4	749.4
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]
Long-term [Abstract]
Long-term debt		278.7	278.7
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]
Long-term [Abstract]
Long-term debt		559.6	559.6
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]
Long-term [Abstract]
Long-term debt		583.9	583.9
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Long-term [Abstract]
Long-term debt		580.1	580.1
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member]
Long-term [Abstract]
Long-term debt		500.0	500.0
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member]
Long-term [Abstract]
Long-term debt		500.0	500.0
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	[1]	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	[1]	48.1	48.1
Unamortized premium		0.5	0.5
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Long-term [Abstract]
Long-term debt	[2]		150.0
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2017 [Member]
Current:
Accounts receivable securitization facility, due December 2017		$ 285.0	$ 275.0

[1] Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

[2] As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

XML

Debt Obligations (Parenthetical) (Details) - USD ($)		3 Months Ended
		Mar. 31, 2017	Feb. 23, 2017	Dec. 31, 2016
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 350,000,000	$ 275,000,000
Accounts Receivable Securitization Facility Due December 2017 [Member] | Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maturity date		Dec. 31, 2017
Senior Unsecured 5% Notes due January 2018 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Jan. 15, 2018
Interest rate on fixed rate debt		5.00%
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Nov. 15, 2019
Interest rate on fixed rate debt		4.125%
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Aug. 01, 2022
Interest rate on fixed rate debt		6.375%
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		May 01, 2023
Interest rate on fixed rate debt		5.25%
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Nov. 15, 2023
Interest rate on fixed rate debt		4.25%
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Mar. 15, 2024
Interest rate on fixed rate debt		6.75%
Senior Unsecured 5 1/8% Notes due February 2025 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Feb. 28, 2025
Interest rate on fixed rate debt		5.125%
Senior Unsecured 5 3/8% Notes due February 2027 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maturity date		Feb. 28, 2027
Interest rate on fixed rate debt		5.375%
Senior Unsecured 4 3/4% Notes due November 2021 [Member] | Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member]
Debt Instrument [Line Items]
Maturity date	[1]	Nov. 15, 2021
Interest rate on fixed rate debt	[1]	4.75%
Senior Unsecured 5 7/8% Notes due August 2023 [Member] | Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member]
Debt Instrument [Line Items]
Maturity date	[1]	Aug. 01, 2023
Interest rate on fixed rate debt	[1]	5.875%
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 1,600,000,000
Remaining borrowing capacity		$ 1,584,200,000
Maturity date	[2]	Oct. 31, 2020

[1] Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

[2] As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

XML

Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details)	Mar. 31, 2017
Accounts Receivable Securitization Facility [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	1.80%
Weighted average interest rate incurred	1.80%
TRP Revolver [Member]
Range of interest rates and weighted average interest rate [Abstract]
Weighted average interest rate incurred	3.20%
TRP Revolver [Member] | Minimum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	3.00%
TRP Revolver [Member] | Maximum [Member]
Range of interest rates and weighted average interest rate [Abstract]
Range of interest rates incurred	5.30%

XML

Debt Obligations - Additional Information (Details) - Accounts Receivable Securitization Facility [Member] - USD ($)	Mar. 31, 2017	Feb. 23, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 350,000,000	$ 275,000,000
Outstanding securitization facility	$ 285,000,000

XML

Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Other Liabilities Noncurrent [Line Items]
Asset retirement obligations	$ 67.5	$ 64.1
Mandatorily redeemable preferred interests	71.9	68.5
Deferred revenue	69.0	69.8
Other liabilities	3.2	2.9
Total long-term liabilities	676.4	$ 205.3
Permian Acquisition [Member]
Other Liabilities Noncurrent [Line Items]
Permian Acquisition contingent consideration	$ 464.8

XML

Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2016		$ 64.1
Additions	[1]	0.4
Change in cash flow estimate		1.7	$ (9.1)
Accretion expense		1.3	$ 1.1
Balance at March 31, 2017		$ 67.5

[1] Amount reflects AROs assumed from the Permian Acquisition

XML

Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) JointVenture	Mar. 31, 2016 USD ($)
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2016	$ 68.5
Change in estimated redemption value included in interest expense	(2.5)	$ 18.5
Balance at March 31, 2017	71.9
Mandatorily Redeemable Preferred Interests [Member]
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract]
Balance at December 31, 2016	68.5
Income attributable to mandatorily redeemable preferred interests	0.9
Change in estimated redemption value included in interest expense	2.5
Balance at March 31, 2017	$ 71.9
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%

XML

Other Long-term Liabilities, Deferred Revenue (Details) - Channelview Splitter [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)	Dec. 27, 2015 bbl
Deferred Revenue [Abstract]
Crude oil and Condensate split operation per day		35,000
Storage capacity of Channelview Terminal		730,000
Channelview Splitter capability to split crude oil and condensate barrel per day		35,000
Channelview Splitter project expected completion period	2018-06
Channelview Splitter project estimated total cost | $	$ 140.0
Annual deferred revenue payments receivable through 2022 | $	$ 43.0
Deferred revenue recognition period over Splitter Agreement start-up period	2018
Deferred revenue recognition period over Splitter Agreement end period	2025

XML

Other Long-term Liabilities, Components Of Deferred Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 69.0	$ 69.8
Other Deferred Revenue [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	6.7	7.1
Gas Contract Amendment [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	19.3	19.7
Channelview Splitter [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	$ 43.0	$ 43.0

XML

Other Long-term Liabilities, Changes In Deferred Revenue (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Other Liabilities Noncurrent [Abstract]
Balance at December 31, 2016	$ 69.8
Revenue recognized	(0.8)
Balance at March 31, 2017	$ 69.0

XML

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

XML

Partnership Units and Related Matters, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Distributions declared and/or paid by the Partnership [Abstract]
Total Distributions		$ 198.1		$ 203.2
Subsequent Event [Member] | Preferred Unit [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date of declaration for cash distribution	2017-04
Cash distribution declared per unit (in dollars per share)	$ 0.1875
Distributions to preferred unit holders	$ 0.9
Cash distribution to be paid	May 15, 2017
Distributions Declared or Paid [Member]
Distributions declared and/or paid by the Partnership [Abstract]
Date Paid or to be Paid		May 11, 2017	Feb. 10, 2017
Total Distributions		$ 209.6	$ 198.1
Distributions to Targa Resources Corp.		$ 206.8	$ 195.3

XML

Partnership Units and Related Matters - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Oct. 31, 2015	Mar. 31, 2017	Mar. 31, 2016
Limited Partners Capital Account [Line Items]
Contributions from Targa Resources Corp.		$ 655.0	$ 801.0
Distribution to holders of preferred units		$ 2.8
Series A Preferred Units [Member]
Limited Partners Capital Account [Line Items]
Series A preferred limited partners units issued (in units)	5,000,000
Preferred stock, par value (in dollar per share)	$ 25.00
Series A Preferred Units due November 1, 2020 [Member]
Limited Partners Capital Account [Line Items]
Preferred units distribution percentage	9.00%
Series A Preferred Units due November 1, 2020 [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.		$ 655.0

XML

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

XML

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

XML

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

XML

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross asset	$ 45.5	$ 21.9
Pro forma net presentation, asset, total	27.9	5.7
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	45.1	21.9
Pro forma net presentation, asset	27.5	5.7
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.4
Pro forma net presentation, asset	0.4
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	23.9	16.8
Pro forma net presentation, asset, current	10.9	5.7
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	23.8	16.8
Pro forma net presentation, asset	10.8	5.7
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	0.1
Pro forma net presentation, asset	0.1
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	21.6	5.1
Pro forma net presentation, asset, noncurrent	17.0
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross asset	21.3	$ 5.1
Pro forma net presentation, asset	16.7
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	$ 0.3

XML

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Liability [Abstract]
Gross liability	$ (30.1)	$ (75.2)
Pro forma net presentation, liability, total	(12.4)	(52.0)
Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(27.4)	(64.8)
Pro forma net presentation, liability, total	(9.7)	(41.6)
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(2.7)	(10.4)
Pro forma net presentation, liability, total	(2.7)	(10.4)
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	(22.2)	(49.1)
Pro forma net presentation, liability, current	(9.1)	(31.0)
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(20.8)	(46.1)
Pro forma net presentation, liability, current	(7.7)	(28.0)
Current Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(1.4)	(3.0)
Pro forma net presentation, liability, current	(1.4)	(3.0)
Long-term Position [Member]
Derivative Liability [Abstract]
Gross liability	(7.9)	(26.1)
Pro forma net presentation, liability, noncurrent	(3.3)	(21.0)
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(6.6)	(18.7)
Pro forma net presentation, liability, noncurrent	(2.0)	(13.6)
Long-term Position [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(1.3)	(7.4)
Pro forma net presentation, liability, noncurrent	$ (1.3)	$ (7.4)

XML

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Gross collateral	$ 0.1	$ 7.0
Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	0.1	7.0
Current Position [Member]
Derivative Asset [Abstract]
Gross collateral	0.1	7.0
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	$ 0.1	$ 7.0

XML

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

XML

Fair Value Measurements - Additional Information (Details) $ in Millions	Mar. 31, 2017 USD ($) Swap
Fair Value Disclosures [Abstract]
Derivatives financial instruments, fair value, net	$ 15.4
Derivative fair value of net liability if commodity price increases by 10 percent	47.5
Derivative fair value of net asset if commodity price decreases by 10 percent	$ 79.0
Number of natural gas basis swaps categorized as Level 3 | Swap	17

XML

Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts		$ 27.9	$ 5.7
Liabilities from commodity derivative contracts		12.4	52.0
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	37.7	21.0
Liabilities from commodity derivative contracts	[1]	22.1	74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		71.7	68.0
Accounts receivable securitization facility		285.0	275.0
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]	464.8
Carrying Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt			150.0
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]	2.7	2.6
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,057.3	4,057.3
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	37.7	21.0
Liabilities from commodity derivative contracts	[1]	22.1	74.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Cash and cash equivalents		71.7	68.0
Accounts receivable securitization facility		285.0	275.0
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]	464.8
Fair Value [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt			150.0
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]	2.7	2.6
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt		4,169.1	4,101.6
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	35.7	19.6
Liabilities from commodity derivative contracts	[1]	20.8	69.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Accounts receivable securitization facility		285.0	275.0
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]
Long-term debt			150.0
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		4,169.1	4,101.6
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Assets from commodity derivative contracts	[1]	2.0	1.4
Liabilities from commodity derivative contracts	[1]	1.3	4.9
Fair Value [Member] | Level 3 [Member] | Permian Acquisition [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[2]	464.8
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]
Additional cash that may be paid based on potential earn-out payment	[3]	$ 2.7	$ 2.6

[1] The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

[2] We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures.

[3] We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.

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Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period	$ (2.6)
New Level 3 derivative instruments	0.0
Transfers out of Level 3	0.0	[1]
Settlements included in Revenue	0.0
Unrealized gain/(loss) included in OCI	0.0
Balance, end of period	(467.5)
Targa Pipeline Partners LP [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(0.1)
Permian Acquisition [Member] | Contingent Liability [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	(464.8)	[2]
Commodity Derivative Contracts Asset/(Liability) [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Balance, beginning of period	(3.6)
New Level 3 derivative instruments	(0.1)
Transfers out of Level 3	1.6	[1]
Settlements included in Revenue	0.2
Unrealized gain/(loss) included in OCI	2.6
Balance, end of period	0.7
Commodity Derivative Contracts Asset/(Liability) [Member] | Targa Pipeline Partners LP [Member]
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]
Change in fair value of contingent consideration	0.0
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	$ 0.0	[2]

[1] Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

[2] Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

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Related Party Transactions - Targa (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Summary of transactions with Targa [Abstract]
Cash contributions from Targa related to limited partner ownership		$ 641.9	$ 785.0
Targa Resources Corp. [Member]
Summary of transactions with Targa [Abstract]
Targa billings of payroll and related costs included in operating expense		47.0	40.2
Targa allocation of general and administrative expense		42.0	39.9
Cash distributions to Targa based on IDR, GP and common unit ownership	[1]	195.3	61.4
Cash contributions from Targa related to limited partner ownership	[2]	641.9	785.0
Contributions from Targa Resources Corp		$ 13.1	$ 16.0
Percentage of general partner's interest maintained		2.00%

[1] As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on GP and common unit ownership.

[2] The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partnership and 2% to GP. See Note 12 – Partnership Units and Related Matters.

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Related Party Transactions - Targa (Parenthetical) (Details) - Targa Resources Corp. [Member]	3 Months Ended
	Mar. 31, 2017
Related Party Transaction [Line Items]
Percentage of capital contribution towards partner's interest maintained	98.00%
Percentage of general partner's interest maintained	2.00%
Third A&R Partnership Agreement [Member]
Related Party Transaction [Line Items]
Percentage of general partner's interest maintained	2.00%

XML

Contingencies (Details) - Environment Proceeding [Member] - USD ($)	Jan. 31, 2017	Oct. 31, 2016	Jun. 18, 2015
Versado Gas Processors L L C
Loss Contingencies [Line Items]
Ownership interest in joint venture			63.00%
Business Acquisition, Percentage of Voting Interests Acquired		37.00%
New Mexico Environment Department [Member]
Loss Contingencies [Line Items]
Litigation settlement amount	$ 29,223

XML

Other Operating (Income) Expense (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Other Income And Expenses [Abstract]
(Gain) loss on sale or disposal of assets	[1]	$ 16.1	$ 0.9
Miscellaneous business tax		0.1	0.1
Total other operating (income) expense		$ 16.2	$ 1.0

[1] Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale

XML

Other Operating (Income) Expense (Parenthetical) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Other Operating Income Expense [Line Items]
Loss on sale or disposal of assets	[1]	$ (16.1)	$ (0.9)
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 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Cash [Abstract]
Interest paid, net of capitalized interest	[1]	$ 53.5	$ 77.3
Income taxes paid, net of refunds		(0.1)	1.1
Non-cash investing activities [Abstract]
Deadstock commodity inventory transferred to property, plant and equipment		8.3	16.9
Impact of capital expenditure accruals on property, plant and equipment		30.0	13.7
Transfers from materials and supplies inventory to property, plant and equipment		0.4	0.5
Contribution of property, plant and equipment to investment in unconsolidated affiliates		1.0
Change in ARO liability and property, plant and equipment due to revised cash flow estimate		1.7	(9.1)
Non-cash balance sheet movements related to the Permian Acquisition:
Purchase consideration payable recorded for the Permian Acquisition		90.0
Non-cash financing activities [Abstract]
Accrued distributions on unvested equity awards under share compensation arrangements		0.0	0.2
Permian Acquisition [Member]
Non-cash balance sheet movements related to the Permian Acquisition:
Contingent consideration recorded at the acquisition date		461.6
Purchase consideration payable recorded for the Permian Acquisition		$ 90.0
Limited Partners Common [Member]
Non-cash financing activities [Abstract]
Cancellation of treasury units			$ (10.2)

[1] Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

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

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Segment Information, Revenues and Operating Margin (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) Segment	Mar. 31, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of segments | Segment	2
Revenues [Abstract]
Sales of commodities	$ 1,858.1	$ 1,171.0
Fees from midstream services	254.5	271.4
Revenues	2,112.6	1,442.4
Operating margin	306.5	299.4
Gathering and Processing [Member]
Revenues [Abstract]
Revenues	999.8	640.8
Operating margin	177.4	115.6
Logistics and Marketing [Member]
Revenues [Abstract]
Revenues	1,911.1	1,240.9
Operating margin	130.1	157.0
Other [Member]
Revenues [Abstract]
Revenues	(1.0)	26.8
Operating margin	(1.0)	26.8
Corporate and Elimination [Member]
Revenues [Abstract]
Revenues	(797.3)	(466.1)
Operating Segments [Member]
Revenues [Abstract]
Sales of commodities	1,858.1	1,171.0
Fees from midstream services	254.5	271.4
Revenues	2,112.6	1,442.4
Operating Segments [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	166.7	110.3
Fees from midstream services	118.2	115.8
Revenues	284.9	226.1
Operating Segments [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	1,692.4	1,033.9
Fees from midstream services	136.3	155.6
Revenues	1,828.7	1,189.5
Operating Segments [Member] | Other [Member]
Revenues [Abstract]
Sales of commodities	(1.0)	26.8
Revenues	(1.0)	26.8
Intersegment Eliminations [Member] | Gathering and Processing [Member]
Revenues [Abstract]
Sales of commodities	713.0	412.6
Fees from midstream services	1.9	2.1
Revenues	714.9	414.7
Intersegment Eliminations [Member] | Logistics and Marketing [Member]
Revenues [Abstract]
Sales of commodities	75.4	47.3
Fees from midstream services	7.0	4.1
Revenues	82.4	51.4
Intersegment Eliminations [Member] | Corporate and Elimination [Member]
Revenues [Abstract]
Sales of commodities	(788.4)	(459.9)
Fees from midstream services	(8.9)	(6.2)
Revenues	$ (797.3)	$ (466.1)

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Segment Information, Other Financial Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Mar. 01, 2017	Dec. 31, 2016
Other financial information [Abstract]
Total assets		$ 13,569.8			$ 12,744.9
Goodwill		369.0		$ 159.0	$ 210.0
Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	13,569.8	$ 12,868.6
Goodwill		369.0	393.0
Capital expenditures		174.6	176.9
Gathering and Processing [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	10,780.4	10,219.0
Goodwill		369.0	393.0
Capital expenditures		139.2	103.0
Logistics and Marketing [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	2,687.2	2,501.0
Capital expenditures		34.6	73.1
Other [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	44.8	105.7
Corporate and Elimination [Member] | Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	57.4	42.9
Capital expenditures		$ 0.8	$ 0.8

[1] Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

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Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenue from External Customer [Line Items]
Sales of commodities	$ 1,858.1	$ 1,171.0
Fees from midstream services	254.5	271.4
Total revenues	2,112.6	1,442.4
Natural Gas [Member]
Revenue from External Customer [Line Items]
Sales of commodities	480.9	326.9
NGL [Member]
Revenue from External Customer [Line Items]
Sales of commodities	1,314.9	785.8
Condensate [Member]
Revenue from External Customer [Line Items]
Sales of commodities	43.6	22.2
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Sales of commodities	19.8	9.6
Derivative Activities [Member]
Revenue from External Customer [Line Items]
Sales of commodities	(1.1)	26.5
Fractionating and Treating [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	31.0	30.2
Storage, Terminaling, Transportation and Export [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	99.7	118.4
Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	107.7	105.0
Other [Member]
Revenue from External Customer [Line Items]
Fees from midstream services	$ 16.1	$ 17.8

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Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reconciliation of operating margin to net income (loss):
Operating margin	$ 306.5	$ 299.4
Depreciation and amortization expenses	(191.1)	(193.5)
General and administrative expenses	(45.5)	(43.4)
Goodwill impairment	0.0	(24.0)
Interest expense, net	(58.6)	(46.9)
Other, net	(37.3)	18.8
Income tax (expense) benefit	4.7	0.2
Net income (loss)	$ (21.3)	$ 10.6