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 every Interactive Data File required to be submitted 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 such files). Yes☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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.

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 ~~3, 2019,~~1, 2020, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

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:

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, ~~2019~~2020 (“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 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.

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

						March 31, 2019			December 31, 2018								March 31, 2020		December 31, 2019
						(Unaudited)											(Unaudited)
						(In millions)											(In millions)
ASSETS	ASSETS											ASSETS
Current assets:	Current assets:											Current assets:
Cash and cash equivalents	Cash and cash equivalents					$	111.7		$	203.3		Cash and cash equivalents					$	340.2	$	291.1
Trade receivables, net of allowances of $0.2 and $0.1 million at March 31, 2019 and December 31, 2018							751.7			864.4
Trade receivables, net of allowances of $0.1 and $0.0 million at March 31, 2020 and December 31, 2019												Trade receivables, net of allowances of $0.1 and $0.0 million at March 31, 2020 and December 31, 2019						438.3		855.2
Inventories	Inventories						197.9			164.7		Inventories						100.2		161.5
Assets from risk management activities	Assets from risk management activities						75.9			115.3		Assets from risk management activities						199.7		103.3
Other current assets	Other current assets						24.9			32.2		Other current assets						46.3		54.2
Held for sale assets												Held for sale assets						—		137.7
Total current assets	Total current assets						1,162.1			1,379.9		Total current assets						1,124.7		1,603.0
Property, plant and equipment							18,182.3			17,213.8
Accumulated depreciation and amortization							(4,479.2	)		(4,285.5	)
Property, plant and equipment, net	Property, plant and equipment, net						13,703.1			12,928.3		Property, plant and equipment, net						12,411.3		14,549.0
Intangible assets, net	Intangible assets, net						1,940.2			1,983.2		Intangible assets, net						1,488.0		1,735.0
Goodwill, net							46.6			46.6
Long-term assets from risk management activities	Long-term assets from risk management activities						23.1			34.1		Long-term assets from risk management activities						82.2		35.5
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates						605.9			490.5		Investments in unconsolidated affiliates						736.8		738.7
Other long-term assets	Other long-term assets						50.0			27.5		Other long-term assets						80.3		83.3
Total assets	Total assets					$	17,531.0		$	16,890.1		Total assets					$	15,923.3	$	18,744.5

LIABILITIES AND OWNERS' EQUITY	LIABILITIES AND OWNERS' EQUITY											LIABILITIES AND OWNERS' EQUITY
Current liabilities:	Current liabilities:											Current liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities					$	1,619.4		$	1,636.9		Accounts payable and accrued liabilities					$	824.4	$	1,283.7
Accounts payable to Targa Resources Corp.	Accounts payable to Targa Resources Corp.						171.2			187.4		Accounts payable to Targa Resources Corp.						161.0		193.8
Liabilities from risk management activities	Liabilities from risk management activities						43.3			33.6		Liabilities from risk management activities						41.8		104.1
Current debt obligations	Current debt obligations						318.1			1,027.9		Current debt obligations						280.6		382.2
Held for sale liabilities												Held for sale liabilities						—		6.4
Total current liabilities	Total current liabilities						2,152.0			2,885.8		Total current liabilities						1,307.8		1,970.2
Long-term debt	Long-term debt						6,683.5			5,197.4		Long-term debt						7,204.8		7,005.2
Long-term liabilities from risk management activities	Long-term liabilities from risk management activities						9.4			3.1		Long-term liabilities from risk management activities						30.2		40.8
Deferred income taxes, net	Deferred income taxes, net						23.9			23.9		Deferred income taxes, net						23.0		23.0
Other long-term liabilities	Other long-term liabilities						258.3			233.8		Other long-term liabilities						253.6		260.0
Contingencies (see Note 16)
Contingencies (see Note 13)												Contingencies (see Note 13)
Owners' equity:	Owners' equity:											Owners' equity:
Series A preferred limited partners	Series A preferred limited partners	Issued		Outstanding			120.6			120.6		Series A preferred limited partners	Issued		Outstanding			120.6		120.6
March 31, 2019			5,000,000		5,000,000
December 31, 2018			5,000,000		5,000,000
March 31, 2020												March 31, 2020		5,000,000		5,000,000
December 31, 2019												December 31, 2019		5,000,000		5,000,000
Common limited partners	Common limited partners	Issued		Outstanding			5,961.0			6,227.2		Common limited partners	Issued		Outstanding			2,803.6		5,022.7
March 31, 2019			275,168,410		275,168,410
December 31, 2018			275,168,410		275,168,410
March 31, 2020												March 31, 2020		275,168,410		275,168,410
December 31, 2019												December 31, 2019		275,168,410		275,168,410
General partner	General partner	Issued		Outstanding			797.1			802.6		General partner	Issued		Outstanding			732.6		778.0
March 31, 2019			5,629,136		5,629,136
December 31, 2018			5,629,136		5,629,136
March 31, 2020												March 31, 2020		5,629,136		5,629,136
December 31, 2019												December 31, 2019		5,629,136		5,629,136
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss)						64.8			124.9		Accumulated other comprehensive income (loss)						221.5		122.5
							6,943.5			7,275.3								3,878.3		6,043.8
Noncontrolling interests	Noncontrolling interests						1,460.4			1,270.8		Noncontrolling interests						3,225.6		3,401.5
Total owners' equity	Total owners' equity						8,403.9			8,546.1		Total owners' equity						7,103.9		9,445.3
Total liabilities and owners' equity	Total liabilities and owners' equity					$	17,531.0		$	16,890.1		Total liabilities and owners' equity					$	15,923.3	$	18,744.5

See notes to consolidated financial statements.	See notes to consolidated financial statements.											See notes to consolidated financial statements.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(Unaudited)						(Unaudited)
	(In millions)						(In millions)
Revenues:
Sales of commodities	$	1,976.5		$	2,173.7		$	1,779.7		$	1,976.5
Fees from midstream services		322.9			281.9			269.2			322.9
Total revenues		2,299.4			2,455.6			2,048.9			2,299.4
Costs and expenses:
Product purchases		1,726.0			1,941.0			1,188.3			1,726.0
Operating expenses		190.2			173.2			194.6			190.2
Depreciation and amortization expense		237.4			198.1			239.1			237.4
General and administrative expense		77.7			52.6			57.0			77.7
Impairment of long-lived assets								2,442.8			—
Other operating (income) expense		3.4			0.3			1.1			3.4
Income (loss) from operations		64.7			90.4			(2,074.0	)		64.7
Other income (expense):
Interest income (expense), net		(75.4	)		20.2
Interest expense, net								(93.8	)		(75.4	)
Equity earnings (loss)		2.8			1.5			20.6			2.8
Gain (loss) from financing activities		(1.4	)		—			39.3			(1.4	)
Change in contingent considerations		(9.7	)		(56.1	)		—			(9.7	)
Income (loss) before income taxes		(19.0	)		56.0			(2,107.9	)		(19.0	)
Income tax (expense) benefit		—			—			—			—
Net income (loss)		(19.0	)		56.0			(2,107.9	)		(19.0	)
Less: Net income (loss) attributable to noncontrolling interests		11.4			13.2			(85.3	)		11.4
Net income (loss) attributable to Targa Resources Partners LP	$	(30.4	)	$	42.8		$	(2,022.6	)	$	(30.4	)

Net income attributable to preferred limited partners	$	2.8		$	2.8		$	2.8		$	2.8
Net income (loss) attributable to general partner		(0.7	)		0.8			(40.6	)		(0.7	)
Net income (loss) attributable to common limited partners		(32.5	)		39.2			(1,984.8	)		(32.5	)
Net income (loss) attributable to Targa Resources Partners LP	$	(30.4	)	$	42.8		$	(2,022.6	)	$	(30.4	)

		Three Months Ended March 31,							Three Months Ended March 31,
		2019				2018			2020			2019
					(Unaudited)				(Unaudited)
		(In millions)							(In millions)
Net income (loss)	Net income (loss)	$	(19.0	)		$	56.0	Net income (loss)	$	(2,107.9	)	$	(19.0	)
Other comprehensive income (loss):	Other comprehensive income (loss):							Other comprehensive income (loss):
Commodity hedging contracts:	Commodity hedging contracts:							Commodity hedging contracts:
Change in fair value	Change in fair value		(38.8	)			64.6	Change in fair value		158.9			(38.8	)
Settlements reclassified to revenues	Settlements reclassified to revenues		(21.3	)			26.7	Settlements reclassified to revenues		(59.9	)		(21.3	)
Other comprehensive income (loss)	Other comprehensive income (loss)		(60.1	)			91.3	Other comprehensive income (loss)		99.0			(60.1	)
Comprehensive income (loss)	Comprehensive income (loss)		(79.1	)			147.3	Comprehensive income (loss)		(2,008.9	)		(79.1	)
Less: Comprehensive income (loss) attributable to noncontrolling interests	Less: Comprehensive income (loss) attributable to noncontrolling interests		11.4				13.2	Less: Comprehensive income (loss) attributable to noncontrolling interests		(85.3	)		11.4
Comprehensive income (loss) attributable to Targa Resources Partners LP	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(90.5	)		$	134.1	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(1,923.6	)	$	(90.5	)

																Accumulated																								Accumulated
	Limited					Limited					General					Other			Non-						Limited					Limited					General					Other		Non-
	Partner					Partner					Partner					Comprehensive			controlling						Partner					Partner					Partner					Comprehensive		controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total			Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)		Interests			Total
	(Unaudited)																								(Unaudited)
	(In millions, except units in thousands)																								(In millions, except units in thousands)

Balance, December 31, 2018		5,000	$	120.6			275,168	$	6,227.2			5,629	$	802.6		$	124.9		$	1,270.8		$	8,546.1
Balance, December 31, 2019																										5,000	$	120.6			275,168	$	5,022.7			5,629	$	778.0		$	122.5	$	3,401.5		$	9,445.3
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(18.6	)		(18.6	)		—		—			—		—			—		—			—		(101.2	)		(101.2	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			196.8			196.8			—		—			—		—			—		—			—		10.6			10.6
Other comprehensive income (loss)		—		—			—		—			—		—			(60.1	)		—			(60.1	)		—		—			—		—			—		—			99.0		—			99.0
Net income (loss)		—	2.8				—		(32.5	)		—		(0.7	)		—			11.4			(19.0	)		—	2.8				—		(1,984.8	)		—		(40.6	)		—		(85.3	)		(2,107.9	)
Distributions		—		(2.8	)		—		(233.7	)		—		(4.8	)		—			—			(241.3	)		—		(2.8	)		—		(234.3	)		—		(4.8	)		—		—			(241.9	)
Balance, March 31, 2019		5,000	$	120.6			275,168	$	5,961.0			5,629	$	797.1		$	64.8		$	1,460.4		$	8,403.9
Balance, March 31, 2020																										5,000	$	120.6			275,168	$	2,803.6			5,629	$	732.6		$	221.5	$	3,225.6		$	7,103.9

																Accumulated																								Accumulated
	Limited					Limited					General					Other			Non-						Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling						Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total			Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)																								(Unaudited)
	(In millions, except units in thousands)																								(In millions, except units in thousands)


Balance, December 31, 2017		5,000	$	120.6			275,168	$	6,500.3			5,629	$	808.2		$	(46.0	)	$	475.1		$	7,858.2
Contributions from Targa Resources Corp.		—		—			—		58.8			—		1.2			—			—			60.0
Purchase of noncontrolling interests in subsidiary		—		—			—		—			—		—			—			1.2			1.2
Balance, December 31, 2018																										5,000	$	120.6			275,168	$	6,227.2			5,629	$	802.6		$	124.9		$	1,270.8		$	8,546.1
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(16.5	)		(16.5	)		—		—			—		—			—		—			—			(18.6	)		(18.6	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			280.1			280.1			—		—			—		—			—		—			—			196.8			196.8
Other comprehensive income (loss)		—		—			—		—			—		—			91.3			—			91.3			—		—			—		—			—		—			(60.1	)		—			(60.1	)
Net income (loss)		—		2.8			—		39.2			—		0.8			—			13.2			56.0			—		2.8			—		(32.5	)		—		(0.7	)		—			11.4			(19.0	)
Distributions		—		(2.8	)		—		(221.2	)		—		(4.5	)		—			—			(228.5	)		—		(2.8	)		—		(233.7	)		—		(4.8	)		—			—			(241.3	)
Balance, March 31, 2018	��	5,000	$	120.6			275,168	$	6,377.1			5,629	$	805.7		$	45.3		$	753.1		$	8,101.8
Balance, March 31, 2019																										5,000	$	120.6			275,168	$	5,961.0			5,629	$	797.1		$	64.8		$	1,460.4		$	8,403.9

		Three Months Ended March 31,							Three Months Ended March 31,
		2019			2018				2020			2019
	(Unaudited)							(Unaudited)
	(In millions)							(In millions)
Cash flows from operating activities
Net income (loss)		$	(19.0	)	$	56.0			$	(2,107.9	)	$	(19.0	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense			2.4			2.3				2.5			2.4
Depreciation and amortization expense			237.4			198.1				239.1			237.4
Impairment of long-lived assets										2,442.8			—
Accretion of asset retirement obligations			1.0			0.9				0.7			1.0
Increase (decrease) in redemption value of mandatorily redeemable preferred interests			—			(72.5	)
Equity (earnings) loss of unconsolidated affiliates			(2.8	)		(1.5	)			(20.6	)		(2.8	)
Distributions of earnings received from unconsolidated affiliates			4.8			4.2				21.1			4.8
Risk management activities			7.2			10.9				(115.5	)		7.2
(Gain) loss on sale or disposition of assets			3.2			(0.1	)			0.6			3.2
(Gain) loss from financing activities			1.4			—				(39.3	)		1.4
Change in contingent considerations			9.7			56.1				—			9.7
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets			83.9			114.2				422.9			83.9
Inventories			(60.6	)		110.2				62.3			(60.6	)
Accounts payable and other liabilities			39.0			(124.6	)			(454.2	)		39.0
Net cash provided by operating activities			307.6			354.2				454.5			307.6
Cash flows from investing activities
Outlays for property, plant and equipment			(942.9	)		(595.9	)			(341.7	)		(942.9	)
Proceeds from sale of assets			0.5			—
Proceeds from sale of business and assets										134.8			0.5
Investments in unconsolidated affiliates			(117.4	)		(88.0	)			(1.4	)		(117.4	)
Return of capital from unconsolidated affiliates			—			1.5				2.8			—
Other, net			(9.0	)		5.1				3.6			(9.0	)
Net cash used in investing activities			(1,068.8	)		(677.3	)			(201.9	)		(1,068.8	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facility			750.0			600.0				790.0			750.0
Repayments of credit facility			(780.0	)		(240.0	)			(430.0	)		(780.0	)
Proceeds from borrowings under accounts receivable securitization facility			378.0			—				130.0			378.0
Repayments of accounts receivable securitization facility			(350.4	)		(50.0	)			(231.9	)		(350.4	)
Proceeds from issuance of senior notes			1,500.0							—			1,500.0
Redemption of senior notes			(749.4	)		—				(122.1	)		(749.4	)
Principal payments of finance leases			(2.7	)		—				(3.1	)		(2.7	)
Costs incurred in connection with financing arrangements			(12.8	)		—				—			(12.8	)
Contributions from general partner			—			1.2
Contributions from TRC			—			58.8
Contributions from noncontrolling interests			196.8			280.1				10.6			196.8
Distributions to noncontrolling interests			(18.6	)		(16.5	)			(105.1	)		(18.6	)
Distributions to unitholders			(241.3	)		(228.5	)			(241.9	)		(241.3	)
Net cash provided by financing activities			669.6			405.1
Net cash provided by (used in) financing activities										(203.5	)		669.6
Net change in cash and cash equivalents			(91.6	)		82.0				49.1			(91.6	)
Cash and cash equivalents, beginning of period			203.3			124.7				291.1			203.3
Cash and cash equivalents, end of period		$	111.7		$	206.7			$	340.2		$	111.7

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.

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

Our common units are wholly owned by TRC and no longer publicly traded as a result of TRC’s acquisition of our outstanding common units that it and its subsidiaries did not already own in 2016.

The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred ~~Units”~~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.~~“NGLS/PA.”

See Note 1916 – 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.

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for a fair statement of the results of the interim periods reported. 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. Operating results for the three months ended March 31, ~~2019,~~2020, are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2019~~2020.

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. Other than the updates noted below, there were no significant updates or revisions to our accounting policies during the three months ended March 31, ~~2019.~~2020.

In ~~February 2016,~~August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) ~~2016-02,~~ ~~Leases~~ 2018-13, Fair Value Measurement (Topic ~~842)~~820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements. The amendments in this update ~~supersede~~removed certain fair value measurement disclosure requirements and added a requirement to disclose the ~~leases guidance in Topic 840. We adopted Topic 842~~range and weighted average of significant unobservable inputs used to develop both recurring and nonrecurring Level 3 fair value measurements. The amendments were effective for us on January 1, ~~2019~~2020, and were adopted on a prospective basis, with no material effect on our consolidated financial statements as a result of adoption.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this update modifies the impairment model for financial instruments, including trade and other receivables, held-to-maturity debt securities and other instruments.

The amendment requires entities to consider historical information, current conditions and supportable forecasts to estimate expected credit losses, which may result in earlier recognition of losses. The amendments were effective for us on January 1, 2020, and were adopted by applying the ~~optional~~modified retrospective transition method in ASU-2018-11, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.approach. The adoption ~~of Topic 842~~ did not result in a cumulative effect adjustment to retained earnings on January 1, ~~2019.~~2020. As ~~part of the adoption of Topic 842, we recognized~~ a ~~net right-of-use asset of $64.2 million~~ ~~(net of $0.4 million of lease incentives/deferred rent)~~ ~~and lease liability of $64.6 million. Other practical expedients we elected include:~~

~~We recognize the following for all leases (with the exception of short-term leases) at the commencement date:~~

We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present valueresult of our ~~lease liability. The discount rate applied is determined based on information available on the date of~~ adoption, see Accounting Policy Updates – Allowance for ~~all leases existing as of that date, and on the date of lease commencement for all subsequent leases.~~Doubtful Accounts below.

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the allowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.

We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. These procedures also include performing account reconciliations, dispute resolution and payment confirmation. We may ~~include variable lease payments based on an index~~involve our legal counsel to pursue the recovery of defaulted trade receivables.

As the financial condition of any counterparty changes, circumstances develop or ~~market rate or~~additional information becomes available, adjustments to our allowance may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.

~~Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract~~

~~In August 2018, the FASB issued~~ ~~ASU~~ ~~2018-15,~~ ~~Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract~~. The amendments in this update require customers in a cloud computing arrangement that is a service contract to assess related implementation costs for capitalization using the same approach as implementation costs associated with internal-use software. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. Entities may apply the amendments using a retrospective or prospective transition method. The amendments will be effective for Targa in the first quarter of 2020. We currently plan to apply the prospective transition method and do not expect a material impact on our Consolidated Financial Statements.

In February 2019, we announced an extension of Grand Prix from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with the Williams Companies, Inc. (“Williams”) Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams also had an initial option to purchase a 20% equity interest in one of our recently announced 110 MBbl/d fractionation trains (Train 7 or Train 8) in Mont Belvieu. Williams exercised its option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa.

On April 3, 2019, we closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”)for $1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and hold majority governance rights. Future growth capital of Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of Targa Badlands LLC. We will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements.

	March 31, 2019			December 31, 2018			Estimated Useful Lives (In Years)	March 31, 2020			December 31, 2019			Estimated Useful Lives (In Years)
Gathering systems	$	8,417.2		$	7,547.9		5 to 20	$	9,027.1		$	8,976.8		5 to 20
Processing and fractionation facilities		4,287.4			4,001.0		5 to 25		5,363.7			5,137.0		5 to 25
Terminaling and storage facilities		1,173.0			1,138.7		5 to 25		1,498.3			1,495.5		5 to 25
Transportation assets		1,016.8			445.1		10 to 25		2,313.1			2,292.4		10 to 50
Other property, plant and equipment		398.6			334.3		3 to 25		297.8			183.9		3 to 25
Land		149.2			144.3		—		159.2			159.7		—
Construction in progress		2,699.2			3,602.5		—		1,424.9			1,576.5		—
Finance lease right-of-use assets		40.9			—				51.2			48.8
Property, plant and equipment		18,182.3			17,213.8				20,135.3			19,870.6
Accumulated depreciation and amortization		(4,479.2	)		(4,285.5	)
Accumulated depreciation, amortization and impairment									(7,724.0	)		(5,321.6	)
Property, plant and equipment, net	$	13,703.1		$	12,928.3			$	12,411.3		$	14,549.0

Intangible assets	$	2,736.6		$	2,736.6		10 to 20	$	2,643.5		$	2,643.5		10 to 20
Accumulated amortization		(796.4	)		(753.4	)
Accumulated amortization and impairment									(1,155.5	)		(908.5	)
Intangible assets, net	$	1,940.2		$	1,983.2			$	1,488.0		$	1,735.0

During the preparation of the Company's consolidated financial statements for the three months ended March 31, 2019, the Company identified an error related to depreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company has recorded the cumulative impact of the adjustment in the three months ended March 31, 2019. This adjustment resulted in a one-time $12.5 million overstatement of depreciation expense during the three months ended March 31, 2019.

During the three months ended March 31, ~~2019~~2020 and ~~2018,~~2019, depreciation expense was ~~$194.4~~$200.7 million and ~~$152.4~~$194.4 million.

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates could have an impact on our assessment of asset recoverability.

During the first quarter of 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter from certain major oil producing nations increasing production significantly also contributed to the sharp drop in commodity prices. The sharp drop in commodity prices has resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. The likelihood of additional domestic production shut-ins increases as the availability of domestic crude oil storage decreases, commodity prices remain depressed and concerns about a global oversupply of crude from reduced demand associated with COVID-19 continues.

The above circumstances are a triggering event that requires long-lived assets to be evaluated for impairment. At March 31, 2020, we determined that indictors of impairment existed for certain asset groups reported primarily within our Gathering and Processing segment. For each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value, fair value was determined through use of discounted estimated cash flows to measure the impairment loss.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use.

The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement The significant unobservable inputs used include discount rates and terminal value exit multiples. We utilized a weighted average discount rate of 14.0% when deriving the fair value of the asset groups impaired during the quarter. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a market participant would utilize.

For the three months ended March 31, 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The carrying value adjustments are included in Impairment of long-lived assets in our Consolidated Statements of Operations.

The above impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Based on the current market conditions, our first quarter impairment assessment forecasts further decline in natural gas production across the Mid-Continent and Gulf of Mexico.

We may identify additional triggering events in the future which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.

Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. ~~We are amortizing these assets over lives ranging from 10~~

As a result of the triggering events and analysis described above, for the three months ended March 31, 2020 we recognized a non-cash pre-tax impairment loss associated with certain intangible customer relationships for which undiscounted future net cash flows were not sufficient to ~~20 years~~ ~~using a method that closely reflects~~recover the ~~cash flow pattern underlying their valuation, or the straight-line method, if a reliably determinable pattern of amortization could not be identified.~~net book value.

The estimated annual amortization expense for intangible assets is approximately ~~$171.6~~$139.1 million, ~~$159.4~~$129.2 million, ~~$149.5~~$120.9 million, ~~$141.2~~$115.7 million and ~~$136.0~~$111.9 million for each of the years ~~2019~~2020 through ~~2023.~~2024.

Investments in GCF, the Cayenne Joint Venture, GCX and the Agua Blanca Joint Venture are included in the total assets of our Logistics and Marketing segment. Investments in the T2 Joint Ventures and the Little Missouri 4 ~~Joint Venture~~ ~~are included in the total assets of our Gathering and Processing segment. See Note 19~~ – ~~Segment Information for more information regarding our segment assets.~~

The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.

The T2 Joint Ventures were formed to provide services for the benefit of their joint ~~interest~~venture owners and have capacity lease agreements with their joint ~~interest~~venture owners, which cover costs of operations (excluding depreciation and amortization). ~~On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures.~~

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

	Balance at December 31, 2018		Equity Earnings (Loss)			Cash Distributions			Contributions		Balance at March 31, 2019		Balance at December 31, 2019		Equity Earnings (Loss)			Distributions			Contributions		Balance at March 31, 2020
GCX (1)													$	447.5	$	16.4		$	(21.0	)	$	1.4	$	444.3
Little Missouri 4														103.7		3.3			—			—		107.0
T2 Eagle Ford ~~(1)~~(2)														89.6		(2.2	)		(0.9	)		—		86.5
T2 LaSalle (2)														44.8		(1.2	)		(0.4	)		—		43.2
GCF	$	40.3	$	4.3		$	(2.2	)	$	—	$	42.4		37.2		2.4			(1.6	)		—		38.0
T2 LaSalle (1)		49.3		(1.5	)		—			—		47.8
T2 Eagle Ford ~~(1)~~(2)		99.0		(2.4	)		—			—		96.6
Cayenne		16.6		1.9			(2.6	)		—		15.9		15.9		1.9			—			—		17.8
GCX (2)		211.6		0.6			—			110.4		322.6
Little Missouri 4		67.3		—			—			7.0		74.3
Agua Blanca		6.4		(0.1	)		—			—		6.3
Total	$	490.5	$	2.8		$	(4.8	)	$	117.4	$	605.9	$	738.7	$	20.6		$	(23.9	)	$	1.4	$	736.8

	March 31, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Commodities	$	779.3	$	721.9	$	318.6	$	683.6
Other goods and services		379.4		474.5		264.1		311.5
Interest		91.0		79.4		107.5		125.4
Permian Acquisition contingent consideration		317.9		308.2
Income and other taxes		40.4		45.4		36.2		62.0
Accrued distributions to noncontrolling interests						87.8		91.7
Other		11.4		7.5		10.2		9.5
	$	1,619.4	$	1,636.9	$	824.4	$	1,283.7

Accounts payable and accrued liabilities includes ~~$28.9~~$9.4 million and ~~$52.2~~$21.6 million of liabilities to creditors to whom we have issued checks that remained outstanding as of March 31, ~~2019~~2020 and December 31, ~~2018.~~

As a result of a 2017 acquisition of certain gas gathering and processing and crude gathering assets in the Permian Basin (the “Permian Acquisition”), we have included the related contingent consideration in accounts payable and accrued liabilities as of March 31, 2019, and December 31, 2018. The Permian Acquisition contingent consideration represents the second earn-out payment, which will be paid in May 2019, and is derived on a multiple of realized gross margin during the earn-out period from contracts that existed on March 1, 2017, in accordance with the terms of the purchase and sale agreements. The first potential earn-out payment would have occurred in May 2018 and expired with no required payment.

~~Changes in the value of the contingent consideration liability have been included in Other income (expense).~~ ~~For the period from December 31, 2018 to March 31, 2019, the value of~~ ~~the contingent consideration increased~~ ~~by $9.7 million, primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period.~~ ~~During the three months ended March 31, 2018, we recognized $56.0 million of expense in Other income (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.~~

	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Current:
Accounts receivable securitization facility, due December 2019 (1)	$	307.6		$	280.0
Senior unsecured notes, 4⅛% fixed rate, due November 2019		—			749.4
		307.6			1,029.4
Debt issuance costs, net of amortization		—			(1.5	)
Accounts receivable securitization facility, due December 2020 (1)							$	268.1		$	370.0
Finance lease liabilities		10.5			—			12.5			12.2
Current debt obligations		318.1			1,027.9			280.6			382.2

Long-term:
Senior secured revolving credit facility, variable rate, due June 2023 (2)		670.0			700.0			360.0			—
Senior unsecured notes:
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
5⅞% fixed rate, due April 2026		1,000.0			1,000.0
5⅜% fixed rate, due February 2027		500.0			500.0
6½% fixed rate, due July 2027		750.0			—
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								491.9			500.0
5⅞% fixed rate, due April 2026								992.7			1,000.0
5⅜% fixed rate, due February 2027								490.1			500.0
6½% fixed rate, due July 2027								714.9			750.0
5% fixed rate, due January 2028		750.0			750.0			719.9			750.0
6⅞% fixed rate, due January 2029		750.0			—
TPL notes, 4¾% fixed rate, due November 2021 (3)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (3)		48.1			48.1
6⅞% fixed rate, due January 2029								689.9			750.0
5½% fixed rate, due March 2030								988.0			1,000.0
TPL notes, 4¾% fixed rate, due November 2021 (3)								6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (3)								48.1			48.1
Unamortized premium		0.3			0.3			0.2			0.3
		6,698.5			5,228.5			7,225.8			7,028.5
Debt issuance costs, net of amortization		(42.7	)		(31.1	)		(46.2	)		(49.1	)
Finance lease liabilities		27.7			—			25.2			25.8
Long-term debt		6,683.5			5,197.4			7,204.8			7,005.2
Total debt obligations	$	7,001.6		$	6,225.3		$	7,485.4		$	7,387.4
Irrevocable standby letters of credit outstanding (2)	$	69.8		$	79.5		$	73.1		$	88.2

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, ~~2019:~~2020:

As of March 31, ~~2019,~~2020, we were in compliance with the covenants contained in our various debt agreements.

During the three months ended March 31, 2020, we repurchased on the open market a portion of our outstanding senior notes as follows:

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

The following table summarizes payment obligations for debt instruments after giving effect to the debt repurchases detailed above:

In ~~January 2019,~~April, we ~~issued $750.0 million~~repurchased on the open market a portion of ~~6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full~~ our outstanding ~~4⅛% Senior Notes due 2019~~senior notes as follows:

On April 22, 2020, we amended our Securitization Facility to decrease the facility size from $400.0 million to $250.0 million to more closely align with expectations for borrowing capacity given current commodity prices and to extend the ~~remainder used for general partnership purposes, which included repaying borrowings under our credit facilities.~~facility termination date to April 21, 2021.

~~In February 2019, we redeemed in full our outstanding 4~~⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash loss to write-off $1.4 million of unamortized debt issuance costs, which is included in Gain (loss) from financing activities in the Consolidated Statements of Operations.

~~Our~~deferred revenue, asset retirement obligations ~~(“ARO”) primarily relate to certain gas gathering pipelines, processing facilities~~ and ~~transportation assets.~~operating lease liabilities.

We have certain long-term contractual arrangements for which we have received consideration that we are not yet able to recognize as revenue. The resulting deferred revenue will be recognized once all conditions for revenue recognition have been met.

Deferred revenue as of March 31, 2020 and December 31, 2019, was $171.4 million and $172.0 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is ~~currently~~ dependent ~~upon resolution~~on the outcome of ~~the dispute~~current litigation with Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems.

We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal assets. We have finance leases primarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 6 years, some of which include options to extend the lease term for up to 10 years.

~~The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows:~~

Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense were as follows:

The weighted-average remaining lease terms for operating leases and finance leases are 4 years and 3 years, respectively. The weighted-average discount rates for operating leases and finance leases are 3.9% and 3.9%, respectively.

~~The following table presents the maturities of our lease liabilities under non-cancellable leases as of March 31, 2019:~~

~~The following table presents future minimum payments under non-cancellable leases as of December 31, 2018:~~

TRC is entitled to receive all Partnership distributions after payment of preferred unit distributions each quarter.

The following table details the distributions declared and paid by us for the three months ended March 31, ~~2019:~~2020:

All capital contributions to us continue to be allocated 98% to the limited partner and 2% to our general partner; however, no0 units will be issued for those contributions. During the three months ended March 31, ~~2019,~~2020, TRC did ~~not~~0t make any contributions to us.

Our Preferred Units rank senior to our common units with respect to the distribution rights. Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

We paid $2.8 million of distributions to the holders of Preferred Units (“Preferred Unitholders”) for the three months ended March 31, ~~2019.~~2020.

In April ~~2019,~~2020, 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 that will be paid on May 15, ~~2019.~~

Note 1310 — ~~Derivative Instruments~~Derivative Instruments and Hedging Activities

The primary ~~purpose~~purposes of our commodity risk management activities isare to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and ~~Marketing~~Transportation segment and (iii) natural gas transportation basis risk in our Logistics and ~~Marketing~~Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are designated as cash flow hedges for accounting purposes.

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

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

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

At March 31, ~~2019,~~2020, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2019		2020		2021		2022		2023		Instrument	Unit	2020		2021		2022		2023		2024
Natural Gas	Swaps	MMBtu/d		175,364		79,930		52,055		-		-	Swaps	MMBtu/d		167,230		165,121		86,100		20,000		-
Natural Gas	Basis Swaps	MMBtu/d		111,100		189,119		166,658		150,000		95,000	Basis Swaps	MMBtu/d		436,064		399,360		268,363		220,000		50,000
NGL	Swaps	Bbl/d		17,903		13,267		3,676		-		-	Swaps	Bbl/d		26,012		14,151		8,991		-		-
NGL	Futures	Bbl/d		9,735		4,645		-		-		-	Futures	Bbl/d		15,527		3,521		-		-		-
NGL	Options	Bbl/d		410		-		-		-		-
Condensate	Swaps	Bbl/d		4,266		2,390		1,404		-		-	Swaps	Bbl/d		6,390		4,204		1,610		-		-
Condensate	Options	Bbl/d		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 value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of March 31, 2019				Fair Value as of December 31, 2018					Fair Value as of March 31, 2020				Fair Value as of December 31, 2019
	Balance Sheet	Derivative		Derivative		Derivative		Derivative		Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities		Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	72.5	$	25.2	$	112.5	$	18.9	Current	$	190.9	$	15.6	$	102.1	$	11.6
	Long-term		20.4		3.1		31.6		1.5	Long-term		69.3		24.9		33.7		6.4
Total derivatives designated as hedging instruments		$	92.9	$	28.3	$	144.1	$	20.4		$	260.2	$	40.5	$	135.8	$	18.0
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	3.4	$	18.1	$	2.8	$	14.7	Current	$	8.8	$	26.2	$	1.2	$	92.5
	Long-term		2.7		6.3		2.5		1.6	Long-term		12.9		5.3		1.8		34.4
Total derivatives not designated as hedging instruments		$	6.1	$	24.4	$	5.3	$	16.3		$	21.7	$	31.5	$	3.0	$	126.9
Total current position		$	75.9	$	43.3	$	115.3	$	33.6		$	199.7	$	41.8	$	103.3	$	104.1
Total long-term position			23.1		9.4		34.1		3.1			82.2		30.2		35.5		40.8
Total derivatives		$	99.0	$	52.7	$	149.4	$	36.7		$	281.9	$	72.0	$	138.8	$	144.9

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

		Gross Presentation								Pro Forma Net Presentation						Gross Presentation								Pro Forma Net Presentation
March 31, 2019		Asset		Liability			Collateral			Asset		Liability
March 31, 2020															March 31, 2020	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position														Current Position
	Counterparties with offsetting positions or collateral	$	69.0	$	(42.0	)	$	(7.3	)	$	43.5	$	(23.8	)	Counterparties with offsetting positions or collateral	$	157.2	$	(41.8	)	$	(11.9	)	$	120.8	$	(17.3	)
	Counterparties without offsetting positions - assets		6.9		-			-			6.9		-		Counterparties without offsetting positions - assets		42.5		-			-			42.5		-
	Counterparties without offsetting positions - liabilities		-		(1.3	)		-			-		(1.3	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			75.9		(43.3	)		(7.3	)		50.4		(25.1	)			199.7		(41.8	)		(11.9	)		163.3		(17.3	)
Long Term Position	Long Term Position														Long Term Position
	Counterparties with offsetting positions or collateral		19.0		(9.1	)		-			13.5		(3.6	)	Counterparties with offsetting positions or collateral		61.4		(30.2	)		-			31.4		(0.2	)
	Counterparties without offsetting positions - assets		4.1		-			-			4.1		-		Counterparties without offsetting positions - assets		20.8		-			-			20.8		-
	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			23.1		(9.4	)		-			17.6		(3.9	)			82.2		(30.2	)		-			52.2		(0.2	)
Total Derivatives	Total Derivatives														Total Derivatives
	Counterparties with offsetting positions or collateral		88.0		(51.1	)		(7.3	)		57.0		(27.4	)	Counterparties with offsetting positions or collateral		218.6		(72.0	)		(11.9	)		152.2		(17.5	)
	Counterparties without offsetting positions - assets		11.0		-			-			11.0		-		Counterparties without offsetting positions - assets		63.3		-			-			63.3		-
	Counterparties without offsetting positions - liabilities		-		(1.6	)		-			-		(1.6	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
		$	99.0	$	(52.7	)	$	(7.3	)	$	68.0	$	(29.0	)		$	281.9	$	(72.0	)	$	(11.9	)	$	215.5	$	(17.5	)

		Gross Presentation								Pro Forma Net Presentation						Gross Presentation								Pro Forma Net Presentation
December 31, 2018		Asset		Liability			Collateral			Asset		Liability
December 31, 2019															December 31, 2019	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position														Current Position
	Counterparties with offsetting positions or collateral	$	100.0	$	(33.6	)	$	(14.2	)	$	70.0	$	(17.8	)	Counterparties with offsetting positions or collateral	$	99.8	$	(85.0	)	$	(4.9	)	$	56.0	$	(46.1	)
	Counterparties without offsetting positions - assets		15.3		-			-			15.3		-		Counterparties without offsetting positions - assets		3.5		-			-			3.5		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-		Counterparties without offsetting positions - liabilities		-		(19.1	)		-			-		(19.1	)
			115.3		(33.6	)		(14.2	)		85.3		(17.8	)			103.3		(104.1	)		(4.9	)		59.5		(65.2	)
Long Term Position	Long Term Position														Long Term Position
	Counterparties with offsetting positions or collateral		8.9		(3.1	)		-			5.9		(0.1	)	Counterparties with offsetting positions or collateral		33.3		(40.5	)		-			18.1		(25.3	)
	Counterparties without offsetting positions - assets		25.2		-			-			25.2		-		Counterparties without offsetting positions - assets		2.2		-			-			2.2		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-		Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			34.1		(3.1	)		-			31.1		(0.1	)			35.5		(40.8	)		-			20.3		(25.6	)
Total Derivatives	Total Derivatives														Total Derivatives
	Counterparties with offsetting positions or collateral		108.9		(36.7	)		(14.2	)		75.9		(17.9	)	Counterparties with offsetting positions or collateral		133.1		(125.5	)		(4.9	)		74.1		(71.4	)
	Counterparties without offsetting positions - assets		40.5		-			-			40.5		-		Counterparties without offsetting positions - assets		5.7		-			-			5.7		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-		Counterparties without offsetting positions - liabilities		-		(19.4	)		-			-		(19.4	)
		$	149.4	$	(36.7	)	$	(14.2	)	$	116.4	$	(17.9	)		$	138.8	$	(144.9	)	$	(4.9	)	$	79.8	$	(90.8	)

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~~brokers that ~~clears~~clear the hedges through an exchange. We maintain a margin deposit with the ~~broker~~brokers 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 value 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 ~~$46.3~~$209.9 million as of March 31, ~~2019.~~2020. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)					Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended March 31,					Three Months Ended March 31,
Hedging Relationships	2019			2018		2020		2019
Commodity contracts	$	(38.8	)	$	64.6	$	158.9	$	(38.8	)

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)					Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended March 31,					Three Months Ended March 31,
Location of Gain (Loss)	2019		2018			2020		2019
Revenues	$	21.3	$	(26.7	)	$	59.9	$	21.3

Based on valuations as of March 31, 2020, we expect to reclassify commodity hedge-related deferred gains of $218.3 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2023, with $173.9 million of gains to be reclassified over the next twelve months.

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. For the three months ended March 31, 2020, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward basis prices.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives						Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended March 31,						Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2019			2018			Derivatives	2020		2019
Commodity contracts	Revenue	$	(9.5	)	$	(10.8	)	Revenue	$	100.0	$	(9.5	)

Based on valuations as of March 31, 2019, we expect to reclassify commodity hedge-related deferred gains of $64.6 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with $47.3 million of gains to be reclassified over the next twelve months.

See Note 1411 – Fair Value Measurements and Note 1916 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

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

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, ~~2019,~~2020, a net asset position of ~~$46.3~~$209.9 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net ~~liability~~asset of ~~$40.1~~$121.9 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of ~~$129.2~~$298.0 million, ignoring an adjustment for counterparty credit risk.

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:

Contingent consideration liabilities related to business acquisitions are carried at fair value until the end of the related earn-out period.

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:

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

			March 31, 2019																March 31, 2020
						Fair Value																Fair Value
			Carrying Value			Total			Level 1			Level 2			Level 3				Carrying Value			Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	97.2		$	97.2		$	—		$	93.3		$	3.9	Assets from commodity derivative contracts (1)		$	277.8		$	277.8		$	—		$	277.8		$	—
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			50.9			50.9			—			50.5			0.4	Liabilities from commodity derivative contracts (1)			67.9			67.9			—			67.9			—
TPL contingent consideration (2)				2.4			2.4			—			—			2.4				2.3			2.3			—			—			2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			111.7			111.7			—			—			—	Cash and cash equivalents			340.2			340.2			—			—			—
TRP Revolver	TRP Revolver			670.0			670.0			—			670.0			—	TRP Revolver			360.0			360.0			—			360.0			—
Senior unsecured notes	Senior unsecured notes			6,028.5			6,268.9			—			6,268.9			—	Senior unsecured notes			6,865.8			5,742.7			—			5,742.7			—
Accounts receivable securitization facility				307.6			307.6			—			307.6			—
Securitization Facility																	Securitization Facility			268.1			268.1			—			268.1			—

		December 31, 2018																December 31, 2019
					Fair Value																Fair Value
			Carrying Value		Total			Level 1			Level 2			Level 3					Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	144.4		$	144.4		$	—		$	137.5		$	6.9	Assets from commodity derivative contracts (1)		$	136.5		$	136.5		$	—		$	136.2		$	0.3
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			31.7			31.7			—			31.3			0.4	Liabilities from commodity derivative contracts (1)			142.6			142.6			—			142.0			0.6
Permian Acquisition contingent consideration (3)				308.2			308.2			—			—			308.2
TPL contingent consideration (2)	TPL contingent consideration (2)			2.4			2.4			—			—			2.4	TPL contingent consideration (2)			2.3			2.3			—			—			2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			203.3			203.3			—			—			—	Cash and cash equivalents			291.1			291.1			—			—			—
TRP Revolver	TRP Revolver			700.0			700.0			—			700.0			—	TRP Revolver			—			—			—			—			—
Senior unsecured notes	Senior unsecured notes			5,277.9			5,088.9			—			5,088.9			—	Senior unsecured notes			7,028.5			7,376.9			—			7,376.9			—
Accounts receivable securitization facility				280.0			280.0			—			280.0			—
Securitization Facility																	Securitization Facility			370.0			370.0			—			370.0			—

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

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities 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, ~~2019,~~2020, we had 130 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 as of December 31, 2018, 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. The Permian Acquisition contingent consideration earn-out period ended on February 28, 2019. The first earn-out payment due in May 2018 expired with no required payment. The second earn-out payment will be paid in May 2019 and is derived on a multiple of realized gross margin during the earn-out period from contracts that existed on March 1, 2017, in accordance with the terms of the purchase and sale agreements. As such, the carrying value of the Permian Acquisition contingent consideration as of March 31, 2019, approximates fair value, as with our other accounts payables. See Note 8 – Accounts Payable and Accr~~ued Liabilities~~ ~~for additional discussion of the Permian Acquisition contingent consideration.~~

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~~valuation of the contingent ~~considerations are~~consideration is categorized in Level 3. ~~Changes in the fair value of these liabilities are included in Other income (expense) in our Consolidated Statements of Operations.~~

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

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment. For the three months ended March 31, 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations. For disclosures related to valuation techniques, see Note 154 – Property, Plant and Equipment and Intangible Assets.

The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.

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) until March 2018, costs of Targa providing management and support services to certain unaffiliated spun-off entities.~~company. 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:~~Targa:

We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies, ~~in 2019,~~ including but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert ~~penalties~~monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.

On February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC entered into a Final Order and Consent Agreement in connection with Targa Badlands LLC’s alleged violation of Subpart ZZZZ of the National Emission Standards for Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposed a $220,000 civil penalty and requires certain compliance improvements.

The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements.

In accordance with the optional exemptions that we elected to apply, the amounts presented in the table above exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue at the amount that we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy; the estimated remaining duration of such contracts primarily ranges from 1 to 2019 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter.

For disclosures related to disaggregated revenue, see Note 1916– Segment Information.

We operate in ~~two~~2 primary segments: (i) Gathering and Processing, and (ii) Logistics and ~~Marketing~~Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North ~~Dakota;~~Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Other contains the ~~results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and~~ mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

	Three Months Ended March 31, 2019											Three Months Ended March 31, 2020
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	247.6	$	1,726.8	$	2.1	$	—		$	1,976.5	$	243.8	$	1,419.6	$	116.3	$	—		$	1,779.7
Fees from midstream services		199.9		123.0		—		—			322.9		118.2		151.0		—		—			269.2
		447.5		1,849.8		2.1		—			2,299.4		362.0		1,570.6		116.3		—			2,048.9
Intersegment revenues
Sales of commodities		822.8		38.4		—		(861.2	)		—		443.2		56.5		—		(499.7	)		—
Fees from midstream services		1.9		5.5		—		(7.4	)		—		1.7		8.2		—		(9.9	)		—
		824.7		43.9		—		(868.6	)		—		444.9		64.7		—		(509.6	)		—
Revenues	$	1,272.2	$	1,893.7	$	2.1	$	(868.6	)	$	2,299.4	$	806.9	$	1,635.3	$	116.3	$	(509.6	)	$	2,048.9
Operating margin	$	229.0	$	152.1	$	2.1	$	—		$	383.2	$	255.7	$	294.0	$	116.3	$	—		$	666.0
Other financial information:
Total assets (1)	$	11,713.9	$	5,644.9	$	87.9	$	84.3		$	17,531.0	$	9,403.7	$	6,347.7	$	16.3	$	155.6		$	15,923.3
Goodwill	$	46.6	$	—	$	—	$	—		$	46.6	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	417.8	$	470.9	$	—	$	16.9		$	905.6	$	116.1	$	177.9	$	—	$	9.8		$	303.8

	Three Months Ended March 31, 2018												Three Months Ended March 31, 2019
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	265.2	$	1,926.3	$	(17.8	)	$	—		$	2,173.7	$	256.9	$	1,726.8	$	(7.2	)	$	—		$	1,976.5
Fees from midstream services		161.3		120.6		—			—			281.9		199.9		123.0		—			—			322.9
		426.5		2,046.9		(17.8	)		—			2,455.6		456.8		1,849.8		(7.2	)		—			2,299.4
Intersegment revenues
Sales of commodities		866.5		55.7		—			(922.2	)		—		822.8		38.4		—			(861.2	)		—
Fees from midstream services		1.9		6.9		—			(8.8	)		—		1.9		5.5		—			(7.4	)		—
		868.4		62.6		—			(931.0	)		—		824.7		43.9		—			(868.6	)		—
Revenues	$	1,294.9	$	2,109.5	$	(17.8	)	$	(931.0	)	$	2,455.6	$	1,281.5	$	1,893.7	$	(7.2	)	$	(868.6	)	$	2,299.4
Operating margin	$	220.8	$	138.4	$	(17.8	)	$	—		$	341.4	$	238.3	$	152.1	$	(7.2	)	$	—		$	383.2
Other financial information:
Total assets (1)	$	10,908.5	$	3,595.1	$	103.0		$	121.1		$	14,727.7	$	11,798.2	$	5,644.9	$	3.6		$	84.3		$	17,531.0
Goodwill	$	256.6	$	—	$	—		$	—		$	256.6	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	273.2	$	251.0	$	—		$	33.8		$	558.0	$	417.8	$	470.9	$	—		$	16.9		$	905.6

The following table shows our consolidated revenues disaggregated by product and service for the periods presented:

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020		2019
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	411.3		$	470.1		$	273.3	$	411.3
NGL		1,408.1			1,607.3			1,161.0		1,396.6
Condensate and crude oil		137.7			86.9			135.7		137.7
Petroleum products		7.6			48.2			49.8		19.1
		1,964.7			2,212.5			1,619.8		1,964.7
Non-customer revenue:
Derivative activities - Hedge		21.3			(28.0	)		59.9		21.3
Derivative activities - Non-hedge (1)		(9.5	)		(10.8	)		100.0		(9.5	)
		11.8			(38.8	)		159.9		11.8
Total sales of commodities		1,976.5			2,173.7			1,779.7		1,976.5

Fees from midstream services:
Revenue recognized from contracts with customers:
NGL transportation and services		36.2			41.1
Gathering and processing								115.9		194.5
NGL transportation, fractionation and services								40.6		36.2
Storage, terminaling and export		79.6			78.2			99.7		79.6
Gathering and processing		194.5			152.1
Other		12.6			10.5			13.0		12.6

Total fees from midstream services		322.9			281.9			269.2		322.9

Total revenues	$	2,299.4		$	2,455.6		$	2,048.9	$	2,299.4

The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented:

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	229.0		$	220.8		$	255.7		$	238.3
Logistics and Marketing operating margin		152.1			138.4
Logistics and Transportation operating margin								294.0			152.1
Other operating margin		2.1			(17.8	)		116.3			(7.2	)
Depreciation and amortization expense		(237.4	)		(198.1	)		(239.1	)		(237.4	)
General and administrative expense		(77.7	)		(52.6	)		(57.0	)		(77.7	)
Interest income (expense), net		(75.4	)		20.2
Impairment of long-lived assets								(2,442.8	)		—
Interest expense, net								(93.8	)		(75.4	)
Equity earnings (loss)								20.6			2.8
Gain (loss) on sale or disposition of business and assets								(0.6	)		(3.2	)
Gain (loss) from financing activities								39.3			(1.4	)
Change in contingent considerations		(9.7	)		(56.1	)		—			(9.7	)
Other, net		(2.0	)		1.2			(0.5	)		(0.2	)
Income (loss) before income taxes	$	(19.0	)	$	56.0		$	(2,107.9	)	$	(19.0	)

Item 2. Management’s Discussion and Analysis ofof 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, ~~2018~~2019 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

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.~~“NGLS/PA.”

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.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and ~~Marketing~~Transportation (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 (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and inThree Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and ~~Marketing~~Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, 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~~exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and ~~Marketing~~Transportation segment also includes the Grand Prix NGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), ~~which are both currently under construction and expected~~a natural gas pipeline transporting volumes from West Texas to ~~fully begin operations in 2019.~~the Gulf Coast. Grand Prix ~~once fully completed, will integrate~~integrates our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets, including these ~~pipeline projects,~~pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the ~~pipeline projects~~pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the ~~results of commodity derivative activities~~ ~~related to Gathering and Processing hedges of equity volumes that are~~ ~~included in operating margin and~~unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

During the first quarter of 2020, global commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Reduced economic activity due to the COVID-19 pandemic combined with the commodity supply surplus has contributed to a sharp drop in crude oil, condensate, NGL and natural gas prices. Furthermore, the recent substantial decline in commodity prices has led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and has also led to some companies shutting in wells. Such price and activity declines negatively impact our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore potentially reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities. The likelihood of additional domestic production shut-ins and declines in our throughput volumes increases as the availability of domestic crude oil storage decreases, commodity prices remain depressed and concerns about a global oversupply of crude from reduced demand associated with COVID-19 continue.

These circumstances have caused significant market volatility and business disruption. In our Gathering and Processing areas of operation, producers are reducing their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services. Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term. As prices have declined, demand for international export, storage and terminaling services has remained relatively constant thus far.

There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing. While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond.

In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provides for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. We also reduced our estimated 2020 net growth capital expenditures to approximately $700 million to $800 million from our previously disclosed range of $1.2 billion to $1.3 billion, which represents a 40 percent reduction at the midpoint of both ranges. The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent. Additionally, we continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.

We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices.

We are currently experiencing no material issues with potential workforce or supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong. However, if any of these circumstances change, our

business could be adversely affected. Additionally, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

In ~~February 2018, in response to increasing production and to meet the infrastructure needs of producers,~~August 2019, we announced ~~plans to construct two~~that we began construction of a new 250 MMcf/d cryogenic natural gas processing ~~plants, each with a processing capacity of 250 MMcf/d. The first~~ plant ~~known as~~in the ~~Hopson~~Midland Basin, the Gateway Plant, ~~began operations at the end of April 2019. The second plant, known as the Pembrook Plant,~~which is expected to begin operations ~~early~~ in the third quarter of ~~2019.~~2020.

In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. ~~We are completing construction of approximately 220 miles of 12-~~In addition to ~~24-inch~~ high-pressure rich gas gathering pipelines ~~across the Delaware Basin. We are also constructing~~and a ~~new 250 MMcf/d cryogenic~~ natural gas processing plant, ~~(the “Falcon Plant”)~~the Falcon Plant, which were placed into service in ~~the Delaware Basin that is expected to begin~~ ~~operations in the fourth quarter of 2019. We have also commenced~~2019, we completed construction of a second 250 MMcf/d cryogenic natural gas processing plant, ~~(the “Peregrine Plant”)~~the Peregrine Plant, late in the ~~Delaware Basin that is expected~~first quarter and expect it to ~~begin operations~~be operational in the second quarter of 2020.

We will provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants. ~~Total growth capital expenditures related to the plants~~

Logistics and ~~high-pressure pipeline system are expected to be approximately $500 million.~~

In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP under which Targa will construct and operate a new 200 MMcf/d natural gas processing plant (“Little Missouri 4”) at Targa’s existing Little Missouri facility. Little Missouri 4 is anticipated to be completed early in the third quarter of 2019.

In May 2017, we announced initial plans to construct a new common carrier NGL pipeline in Texas and New Mexico, which is owned by Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest. Since then,February 2019, we announced an extension to ~~Southern Oklahoma in March 2018 and an extension to Central Oklahoma in February 2019. Each announced extension is 100% owned by Targa.~~

our Grand Prix ~~will transport NGLs from the Permian Basin, North Texas, Southern Oklahoma, and Central Oklahoma to our fractionation and storage complex in the~~ NGL ~~market hub at Mont Belvieu, Texas.~~pipeline system. The ~~pipeline is comprised of four primary segments:~~

~~The three segments noted above are expected to be fully in service in the third quarter of 2019.~~

~~Grand Prix~~ Transportation volumes ~~flowing~~ on the ~~pipeline from the Permian Basin to Mont Belvieu~~ ~~are included in the Grand Prix Joint Venture, while the volumes flowing from North Texas and~~Central Oklahoma ~~to Mont Belvieu~~Extension accrue solely to Targa’s ~~benefit. Total growth capital spending on~~benefit and are not included in Grand Prix ~~including the extensions into Oklahoma, is estimated to be approximately $1.9 billion, with our portion~~Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of ~~growth capital spending estimated to be approximately $1.3 billion.~~which Targa owns a 56% interest.

~~In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 6”),~~ ~~which began operations in early May 2019.~~ The total cost of the fractionation train and related infrastructure is expected to be approximately $350 million. Targa Train 6 LLC, a joint venture between Targa and Stonepeak Infrastructure Partners (“Stonepeak”), owns 100% interest in certain assets associated with Train 6. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, will be funded and owned 100% by Targa.

In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”)~~, which are expected to begin~~. Train 7 began operations late in the first quarter of ~~2020 and~~2020. Train 8 is expected to begin operations at the end of the third quarter of 2020~~respectively. The total cost of these fractionation trains~~. In January 2019, Williams committed to Targa significant volumes which Targa will transport on Grand Prix and ~~related infrastructure is expected to be approximately $825 million. In connection with the Central Oklahoma Extension,~~fractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams ~~exercised its~~was also granted an option to ~~acquire~~purchase a 20% equity interest in ~~Train 7~~the fractionation train, which was originally wholly owned by Targa. Williams exercised its initial option and executed a joint venture agreement with ~~us.~~us with respect to Train 7 in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, ~~including~~ such as storage caverns and brine handling,, will be funded and owned 100% by Targa.

In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and associated load rates. ~~Our current~~With the additional infrastructure, our effective export capacity ~~of 7 MMBbl per month~~ will increase to ~~approximately 11~~up to 15 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The ~~total cost of the~~ expansion ~~and related infrastructure~~ is expected to be ~~approximately $120 million and is expected to be~~fully completed in the third quarter of 2020.

In ~~December~~ ~~2017,~~November 2019, we ~~entered into definitive joint venture~~executed agreements ~~with Kinder Morgan Texas Pipeline LLC (“KMTP”)~~to sell our crude gathering and ~~DCP Midstream Partners, LP (“DCP”) with respect to~~storage business in the ~~joint development~~Permian Delaware for approximately $134 million. The sale closed early in the first quarter of 2020.

During the ~~Gulf Coast Express Pipeline (“GCX Pipeline”)~~,three months ended March 31, 2020, we repurchased a ~~natural gas pipeline from the Waha hub, including direct connections to the tailgate of many~~portion of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Targa GCX Pipeline LLC, a joint venture between us and Stonepeak, and DCP each own a 25% interest, KMTP owns a 35% interest, and Altus Midstream Company owns the remaining 15% interest in GCX. KMTP serves as the construction manager and operator of GCX Pipeline. We have committed significant volumes to GCX Pipeline. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin assets, has committed volumes to the project. GCX Pipeline is designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to be approximately $1.75 billion. GCX Pipeline is expected to be in service in the fourth quarter of 2019.

~~The Channelview Splitter, located at our Channelview Terminal~~outstanding senior notes on the ~~Houston Ship Channel,~~ ~~is currently operating but still being tested by engineering and operations~~ and has an estimated total cost of approximately $160 million. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel and liquefied petroleum gas and will provide segregated storage for the crude and condensate and each of their components. We are working on commercialization of the Channelview Splitter.

In April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for $1.6 billion in cash. We ~~used the net cash proceeds to repay debt and for general corporate purposes,~~ including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and hold majority governance rights. Future growth capital of Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of Targa Badlands LLC.

~~In January 2019, we issued $750.0~~open market, paying $122.1 million ~~of 6½% Senior Notes due July 2027 and $750.0 million of~~ ~~6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full our~~ ~~4⅛% Senior Notes due 2019, at par value~~ plus accrued interest ~~through~~to repurchase $162.7 million of the ~~redemption date,~~ ~~with the remainder used for general partnership purposes,~~notes. The repurchases resulted in a $39.3 million net gain, which included ~~repaying borrowings under~~the write-off of $1.3 million in related debt issuance costs.

During April 2020, we made further repurchases of our ~~credit facilities.~~outstanding senior notes on the open market, paying $117.8 million to repurchase $140.5 million of the notes.

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.

The profitability of our business 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.

Our profitability is also impacted by fee-based ~~contracts.~~ contracts. Our growing fee-related capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in unit fees due to market dynamics such as available commodity throughput does affect profitability.

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.

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, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export 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.~~assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

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, remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

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.

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.

Logistics and ~~Marketing~~Transportation segment gross margin consists primarily of:

The gross margin impacts of ~~our equity volumes~~mark-to-market hedge ~~settlements~~unrealized changes in fair value are reported in Other.

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:

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income (loss) attributable to TRP. 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.

We define Adjusted EBITDA as net income (loss) attributable to TRP before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. 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 holders of our equity interests.

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.

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,						Three Months Ended March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Operating Margin and Gross Margin
Reconciliation of Net Income (Loss) to Operating Margin and Gross Margin
Net income (loss)	$	(19.0	)	$	56.0		$	(2,107.9	)	$	(19.0	)
Depreciation and amortization expense		237.4			198.1			239.1			237.4
General and administrative expense		77.7			52.6			57.0			77.7
Impairment of long-lived assets								2,442.8			—
Interest (income) expense, net		75.4			(20.2	)		93.8			75.4
Equity (earnings) loss								(20.6	)		(2.8	)
(Gain) loss on sale or disposition of assets		3.2			(0.1	)		0.6			3.2
(Gain) loss from financing activities		1.4			—			(39.3	)		1.4
Change in contingent considerations		9.7			56.1
Other, net		(2.6	)		(1.1	)		0.5			9.9
Operating margin		383.2			341.4			666.0			383.2
Operating expenses		190.2			173.2			194.6			190.2
Gross margin	$	573.4		$	514.6		$	860.6		$	573.4

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP	$	(30.4	)	$	42.8		$	(2,022.6	)	$	(30.4	)
Interest (income) expense, net ~~(1)~~		75.4			(20.2	)		93.8			75.4
Depreciation and amortization expense		237.4			198.1			239.1			237.4
Impairment of long-lived assets								2,442.8			—
(Gain) loss on sale or disposition of assets		3.2			(0.1	)		0.6			3.2
(Gain) loss from financing activities (2)		1.4			—
(Gain) loss from financing activities (1)								(39.3	)		1.4
Equity (earnings) loss		(2.8	)		(1.5	)		(20.6	)		(2.8	)
Distributions from unconsolidated affiliates and preferred partner interests, net		6.8			6.9			25.7			6.8
Change in contingent considerations		9.7			56.1
Splitter Agreement (3)		—			10.8
Risk management activities		7.2			9.7			(115.5	)		7.2
Noncontrolling interests adjustments (4)		(7.1	)		(5.1	)
Noncontrolling interests adjustments (2)								(189.4	)		(7.1	)
TRP Adjusted EBITDA	$	300.8		$	297.5		$	414.6		$	291.1

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

		Three Months Ended March 31,												Three Months Ended March 31,
		2019			2018			2019 vs. 2018						2020			2019			2020 vs. 2019
	(In millions)													(In millions)
Revenues:
Sales of commodities		$	1,976.5		$	2,173.7		$	(197.2	)		(9	%)	$	1,779.7		$	1,976.5		$	(196.8	)		(10	%)
Fees from midstream services			322.9			281.9			41.0			15	%		269.2			322.9			(53.7	)		(17	%)
Total revenues			2,299.4			2,455.6			(156.2	)		(6	%)		2,048.9			2,299.4			(250.5	)		(11	%)
Product purchases			1,726.0			1,941.0			(215.0	)		(11	%)		1,188.3			1,726.0			(537.7	)		(31	%)
Gross margin (1)			573.4			514.6			58.8			11	%		860.6			573.4			287.2			50	%
Operating expenses			190.2			173.2			17.0			10	%		194.6			190.2			4.4			2	%
Operating margin (1)			383.2			341.4			41.8			12	%		666.0			383.2			282.8			74	%
Depreciation and amortization expense			237.4			198.1			39.3			20	%		239.1			237.4			1.7			1	%
General and administrative expense			77.7			52.6			25.1			48	%		57.0			77.7			(20.7	)		(27	%)
Impairment of long-lived assets															2,442.8			—			2,442.8			—
Other operating (income) expense			3.4			0.3			3.1		NM				1.1			3.4			(2.3	)		(68	%)
Income (loss) from operations			64.7			90.4			(25.7	)		(28	%)		(2,074.0	)		64.7			(2,138.7	)	NM
Interest income (expense), net			(75.4	)		20.2			(95.6	)	NM
Interest expense, net															(93.8	)		(75.4	)		(18.4	)		24	%
Equity earnings (loss)			2.8			1.5			1.3			87	%		20.6			2.8			17.8		NM
Gain (loss) from financing activities			(1.4	)		—			(1.4	)		—			39.3			(1.4	)		40.7		NM
Change in contingent considerations			(9.7	)		(56.1	)		46.4			83	%		—			(9.7	)		9.7			100	%
Net income (loss)			(19.0	)		56.0			(75.0	)		(134	%)		(2,107.9	)		(19.0	)		(2,088.9	)	NM
Less: Net income (loss) attributable to noncontrolling interests			11.4			13.2			(1.8	)		(14	%)		(85.3	)		11.4			(96.7	)	NM
Net income (loss) attributable to Targa Resources Partners LP		$	(30.4	)	$	42.8		$	(73.2	)		(171	%)	$	(2,022.6	)	$	(30.4	)	$	(1,992.2	)	NM
Financial data:
Adjusted EBITDA (1)		$	300.8		$	297.5		$	3.3			1	%	$	414.6		$	291.1		$	123.5			42	%
Growth capital expenditures (2)			870.0			535.6			334.4			62	%		277.0			187.0			90.0			48	%
Maintenance capital expenditures (3)			35.6			22.4			13.2			59	%		26.8			870.0			(843.2	)		(97	%)

Three Months Ended March 31, ~~2019~~2020 Compared to Three Months Ended March 31, ~~2018~~2019

The decrease in commodity sales reflects lower NGL, natural gas, and condensate prices ($~~437.8~~863.3 million) and lower ~~petroleum~~crude marketing volumes ~~due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018~~ ($~~40.5~~37.9 million), partially offset by higher NGL, natural gas, petroleum products, and ~~crude marketing~~condensate volumes ($~~228.4~~547.9 million) and the favorable impact of hedges ($~~50.5~~148.0 million).

The ~~increase~~decrease in ~~fee-based revenue was~~fees from midstream services is primarily due to ~~higher gas processing~~new transportation arrangements for Badlands volumes during the three months ended March 31, 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and ~~crude gathering fees.~~product purchases, partially offset by increased export volumes.

The decrease in product purchases reflects decreased NGL, natural gas and condensate prices, partially offset by increases in volumes.

~~The higher~~Higher operating margin and gross margin in ~~2019~~2020 reflect increased segment ~~margin~~ results for Gathering and Processing and Logistics and ~~Marketing.~~Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including the Permian Basin Segment of Grand Prix, and additional processing plants and associated infrastructure in the Permian Basin. The increase is partially offset by lower depreciation for our downstream facilities, resulting from the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018.

General and administrative expense ~~increased~~decreased primarily due to ~~higher~~lower compensation and benefits ~~including increased staffing levels, system~~ costs and lower outside professional services.

The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Based on the current market conditions, our first quarter impairment assessment projects further decline in natural gas production across the Mid-Continent and Gulf of Mexico. We did not recognize any impairments of long-lived assets during the first quarter of 2019. We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments.

Interest expense, net, increased due to ~~a reduction of non-cash interest income related to the mandatorily redeemable interests, and~~ higher average borrowings and lower capitalized interest resulting from lower growth investments.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4.

During the three months ended March 31, 2020, we repurchased a portion of our outstanding senior notes on the open market, paying $122.1 million plus accrued interest to repurchase $162.7 million of the notes, resulting in a $39.3 million net gain from financing activities.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to impairment losses allocated to noncontrolling interest holders, partially offset by ~~higher capitalized~~income allocated to noncontrolling interest ~~related to our major growth investments. During 2018, we recognized non-cash interest income resulting from a decrease~~holders in Targa Badlands LLC (“Targa Badlands”), Targa GCX Pipeline LLC and the ~~estimated redemption value of the mandatorily redeemable interests, primarily attributable to~~ ~~the February 2018 amendments to such arrangements.~~Grand Prix Joint Venture.

~~During 2019, we recorded expense of $9.7 million resulting from an increase in the value of the Permian Acquisition contingent consideration liability.~~ ~~The increase in 2019~~ was primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period. During 2018, we recorded expense of $56.1 million resulting primarily from the increase in fair value as of March 31, 2018 of the Permian Acquisition contingent consideration liability. The fair value change was primarily related to an increase in underlying forecasted volumes for the remainder of the earn-out period and a shorter term over which such projections are discounted.

		Gathering and Processing		Logistics and Marketing		Other			Consolidated Operating Margin		Gathering and Processing		Logistics and Transportation		Other			Consolidated Operating Margin
	(In millions)										(In millions)
Three Months Ended:	Three Months Ended:
March 31, 2020											$	255.7	$	294.0	$	116.3		$	666.0
March 31, 2019		$	229.0	$	152.1	$	2.1		$	383.2		238.3		152.1		(7.2	)		383.2
March 31, 2018			220.8		138.4		(17.8	)		341.4

	Three Months Ended March 31,									Three Months Ended March 31,
	2019		2018		2019 vs. 2018					2020		2019		2020 vs. 2019
	(In millions, except operating statistics and price amounts)									(In millions, except operating statistics and price amounts)
Gross margin	$	351.9	$	325.6	$	26.3		8	%	$	370.3	$	361.2	$	9.1		3	%
Operating expenses		122.9		104.8		18.1		17	%		114.6		122.9		(8.3	)	(7	%)
Operating margin	$	229.0	$	220.8	$	8.2		4	%	$	255.7	$	238.3	$	17.4		7	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,334.4		1,014.1		320.3		32	%		1,655.0		1,322.6		332.4		25	%
Permian Delaware		480.4		409.2		71.2		17	%		727.0		480.4		246.6		51	%
Total Permian		1,814.8		1,423.3		391.5					2,382.0		1,803.0		579.0

SouthTX (5)		363.9		416.3		(52.4	)	(13	%)		286.3		363.9		(77.6	)	(21	%)
North Texas		230.5		235.1		(4.6	)	(2	%)		223.4		230.5		(7.1	)	(3	%)
SouthOK (6)		620.0		529.9		90.1		17	%		564.0		620.0		(56.0	)	(9	%)
WestOK		338.1		350.1		(12.0	)	(3	%)		291.6		338.1		(46.5	)	(14	%)
Total Central		1,552.5		1,531.4		21.1					1,365.3		1,552.5		(187.2	)

Badlands (7)		96.9		73.3		23.6		32	%
Badlands (7),(8)											159.7		96.9		62.8		65	%
Total Field		3,464.2		3,028.0		436.2					3,907.0		3,452.4		454.6

Coastal		769.9		724.3		45.6		6	%		784.7		769.9		14.8		2	%

Total		4,234.1		3,752.3		481.8		13	%		4,691.7		4,222.3		469.4		11	%
NGL production, MBbl/d (3)
Permian Midland (4)		184.3		140.2		44.1		31	%		244.9		184.3		60.6		33	%
Permian Delaware		60.5		45.7		14.8		32	%		96.3		60.5		35.8		59	%
Total Permian		244.8		185.9		58.9					341.2		244.8		96.4

SouthTX (5)		48.8		54.1		(5.3	)	(10	%)		28.2		48.8		(20.6	)	(42	%)
North Texas		26.8		25.9		0.9		3	%		26.3		26.8		(0.5	)	(2	%)
SouthOK (6)		58.3		48.9		9.4		19	%		66.8		58.3		8.5		15	%
WestOK		24.1		19.4		4.7		24	%		23.2		24.1		(0.9	)	(4	%)
Total Central		158.0		148.3		9.7					144.5		158.0		(13.5	)

Badlands(8)		11.4		10.2		1.2		12	%		18.1		11.4		6.7		59	%
Total Field		414.2		344.4		69.8					503.8		414.2		89.6

Coastal		48.4		42.6		5.8		14	%		48.8		48.4		0.4		1	%

Total		462.6		387.0		75.6		20	%		552.6		462.6		90.0		19	%
Crude oil gathered, Badlands, MBbl/d		169.5		117.7		51.8		44	%		177.1		169.5		7.6		4	%
Crude oil gathered, Permian, MBbl/d(9)		67.4		49.4		18.0		36	%		50.9		76.5		(25.6	)	(33	%)
Natural gas sales, BBtu/d (3)		1,925.9		1,767.3		158.6		9	%
NGL sales, MBbl/d		359.5		300.4		59.1		20	%
Natural gas sales, BBtu/d (3),(10)											2,157.2		1,925.9		231.3		12	%
NGL sales, MBbl/d (3),(10)											433.5		359.7		73.8		21	%
Condensate sales, MBbl/d		12.5		16.2		(3.7	)	(23	%)		18.6		12.5		6.1		49	%
Average realized prices (8):
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu		1.89		2.37		(0.48	)	(20	%)		0.93		1.94		(1.01	)	(53	%)
NGL, $/gal		0.45		0.59		(0.14	)	(24	%)		0.22		0.45		(0.22	)	(50	%)
Condensate, $/Bbl		47.09		59.66		(12.57	)	(21	%)		43.95		47.08		(3.13	)	(7	%)

The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering and Processing segment:

Three Months Ended March 31, ~~2019~~2020 Compared to Three Months Ended March 31, ~~2018~~2019

The increase in gross margin was primarily due to higher ~~Badlands~~volumes in the Permian and ~~Permian volumes,~~Badlands, partially offset by lower ~~commodity prices~~Central volumes and lower ~~SouthTX volumes. The effect of~~realized commodity ~~prices excludes the impact of hedging activities presented in Other.~~prices. NGL production and NGL sales increased primarily due to higher natural gas inlet volumes and ~~natural~~increased NGL recoveries. Natural gas sales increased primarily due to higher ~~Field Gathering and Processing~~inlet volumes. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019. In the Badlands, natural gas gathered volumes and NGL ~~recoveries including reduced ethane rejection.~~production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. Total crude oil gathered volumes in the Permian decreased due to the sale of the Delaware crude gathering system in the fourth quarter of 2019. Total crude oil gathered volumes increased in the ~~Permian region~~Badlands due to production from new wells. ~~In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions.~~

~~The increase in~~Lower operating expenses ~~was primarily driven~~attributable to contract labor, taxes and chemicals were partially offset by ~~gas plant~~higher compensation and ~~system expansions~~benefits related to the addition of new facilities in the ~~Permian region. Operating expenses in other regions were relatively flat.~~Permian.

		Three Months Ended March 31,										Three Months Ended March 31,
		2019		2018		2019 vs. 2018						2020		2019		2020 vs. 2019
	(In millions, except operating statistics and price amounts)										(In millions, except operating statistics and price amounts)
Gross margin		$	219.5	$	206.9	$	12.6		6	%		$	375.0	$	219.5	$	155.5		71	%
Operating expenses			67.4		68.5		(1.1	)	(2	%)			81.0		67.4		13.6		20	%
Operating margin		$	152.1	$	138.4	$	13.7		10	%		$	294.0	$	152.1	$	141.9		93	%
Operating statistics MBbl/d (1):
Fractionation volumes (2)			456.6		389.7		66.9		17	%			625.3		456.6		168.7		37	%
Export volumes (3)			213.1		201.9		11.2		6	%			268.9		213.1		55.8		26	%
Pipeline throughput (4)													261.7		-		261.7		-
NGL sales			586.2		514.8		71.4		14	%			748.2		584.3		163.9		28	%
Average realized prices:
NGL realized price, $/gal		$	0.60	$	0.76	$	(0.16	)	(21	%)		$	0.40	$	0.60	$	(0.20	)	(33	%)

Three Months Ended March 31, ~~2019~~2020 Compared to Three Months Ended March 31, ~~2018~~2019

The increase in Logistics and ~~Marketing~~Transportation gross margin was primarily due to higher NGL transportation and fractionation volumes and higher LPG export volumes. Segment gross margin increased due to higher NGL transportation and fractionation margin, higher LPG export margin, and higher marketing margin. NGL transportation and fractionation margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation ~~margin, partially offset by lower terminaling and storage throughput, and lower commercial transportation margin. LPG export margin increased primarily due to higher~~ volumes ~~despite restrictions and temporary closures~~as a result of the ~~Houston Ship Channel during~~commencement of operations of Train 6 in the ~~quarter. Fractionation~~second quarter of 2019 and Train 7 in the first quarter of 2020. LPG export margin increased due to higher ~~supply volume, partially offset by lower system product gains. Fractionation~~volumes in the first quarter of 2020 compared to the same period last year. Marketing margin ~~was partially impacted by the variable effects of fuel and power that are largely reflected in operating expenses (see footnote (2) above). Terminaling and storage throughput decreased~~increased due to ~~the sale~~optimization of ~~certain petroleum logistics storage~~gas and ~~terminaling facilities in the fourth quarter of 2018. Commercial transportation margin decreased due to the sale of the Company’s inland marine barge business in the second quarter of 2018.~~ liquids arrangements.

Operating expenses ~~decreased~~increased due to ~~lower~~higher taxes primarily attributable to the full operations of Grand Prix, higher maintenance, and ~~maintenance.~~ higher compensation and benefits attributable to Train 6 and Train 7 operations.

	Three Months Ended March 31,							Three Months Ended March 31,
	2019		2018			2019 vs. 2018		2020		2019			2020 vs. 2019
	(In millions)							(In millions)
Gross margin	$	2.1	$	(17.8	)	$	19.9	$	116.3	$	(7.2	)	$	123.5
Operating margin	$	2.1	$	(17.8	)	$	19.9	$	116.3	$	(7.2	)	$	123.5

Other contains the results of commodity derivative ~~activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and~~activity mark-to-market ~~gain/~~gains/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~~future commodity purchases and sales and natural gas ~~NGL~~transportation basis risk within our Logistics 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~~Transportation segment. See further details of our ~~future plant equity volumes, these hedge positions will move favorably~~risk management program in ~~periods of falling commodity prices~~“Item 3. – Quantitative and ~~unfavorably in periods of rising commodity prices.~~Qualitative Disclosures About Market Risk.”

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

As of March 31, ~~2019,~~2020, we had ~~$111.7~~$340.2 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. 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 or repaying 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~~the impact of COVID-19 on our operations and workforce and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions.”

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 and ~~the Securitization Facility,~~our accounts receivable securitization facility (the “Securitization Facility”), and access to debt markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. 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.

		May 3, 2019				May 1, 2020
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	297.9		Cash on hand	$	288.1
Total availability under the TRP Revolver	Total availability under the TRP Revolver		2,200.0		Total availability under the TRP Revolver		2,200.0
Total availability under the Securitization Facility	Total availability under the Securitization Facility		334.9		Total availability under the Securitization Facility		181.1
			2,832.8				2,669.2

Less:	Outstanding borrowings under the TRP Revolver		—		Outstanding borrowings under the TRP Revolver		(610.0	)
	Outstanding borrowings under the Securitization Facility		(300.0	)	Outstanding borrowings under the Securitization Facility		(181.1	)
	Outstanding letters of credit under the TRP Revolver		(66.0	)	Outstanding letters of credit under the TRP Revolver		(71.6	)
	Total liquidity	$	2,466.8		Total liquidity	$	1,806.5

Other potential capital resources associated with our existing arrangements include:

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 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 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: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Working capital as of March 31, ~~2019~~ 2020 increased ~~$516.0~~$184.1 million compared to December 31, ~~2018.~~ 2019. The increase was primarily attributable to an increase in the ~~February redemption~~current asset position of our ~~4⅛% Senior Notes due 2019, partially offset by~~derivative contracts and a lower ~~cash~~outstanding balance ~~and a decrease in~~on our ~~net risk management asset position due to changes in forward prices of commodities.~~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, as well as joint ventures and/or asset sales, 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.

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of approximately $960 million of capital to the DevCo JVs.

As of March 31, ~~2019,~~2020, total contributions from Stonepeak to the DevCo JVs were ~~$701.3~~$906.5 million. As of March 31, ~~2019,~~2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were ~~$265.0~~$329.6 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

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. As of March 31, ~~2019~~2020, and December 31, ~~2018,~~2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was ~~$6,683.5~~$7,204.8 million and ~~$5,197.4~~$7,005.2 million, respectively.

The majority of our 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 and the Securitization Facility. 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, ~~2019,~~2020, we did not have any interest rate hedges.

In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder was used for general partnership purposes, which included repaying borrowings under our credit facilities.

~~In April~~ 2019, we closed on the sale of a 45% interest in Targa Badlands ~~LLC, the entity that holds substantially all of our assets in North Dakota,~~ to ~~funds managed by~~GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and hold majority governance rights. Future growth Growth capital of Targa Badlands ~~LLC~~after the sale is ~~expected to be~~ funded on a pro rata ownership basis. Targa Badlands ~~LLC will pay an MQD~~pays a minimum quarterly distribution (“MQD”) to ~~Blackstone~~GSO and Targa, with ~~Blackstone~~GSO having a priority right on such MQDs. Additionally, ~~Blackstone’s~~GSO’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. Targa Badlands ~~LLC.~~is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or its other subsidiaries. As of March 31, 2020, the contributions from GSO were $72.4 million.

During the three months ended March 31, 2020, we repurchased a portion of the outstanding senior notes on the open market, paying $122.1 million plus accrued interest to repurchase $162.7 million of the notes, resulting in a $39.3 million net gain, which included the write-off of $1.3 million in related debt issuance costs. We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

During April 2020, we made further repurchases of its outstanding senior notes on the open market, paying $117.8 million to repurchase $140.5 million of the notes.

To date, our debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 97 - 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.”

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 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.

As of March 31, ~~2019,~~2020, we were in compliance with the covenants contained in our various debt agreements.

Three Months Ended March 31,	Three Months Ended March 31,						Three Months Ended March 31,
2019		2018		2019 vs. 2018
2020							2020	2019		2020 vs. 2019
(In millions)	(In millions)						(In millions)
$	307.6	$	354.2	$	(46.6	)	454.5	$	307.6	$	146.9

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for gas processing, crude gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs and natural gas, (iii) changes in payables and accruals related to major growth projects; and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations ~~decreased~~increased in ~~2019~~2020 compared to ~~2018,~~2019 primarily due to ~~the~~higher operating margin and an increase in ~~payments for operating and general and administrative expenses resulting~~cash settlements from ~~system expansions and higher compensation and benefits, and increases~~hedging activity, partially offset by an increase in interest payments ~~due to~~as a result of higher average borrowings, partially offset by the impact of lower commodity prices and increased margin withdrawals related to our derivative contracts. Lower commodity prices resulted in lower product purchases, partially offset by lower cash collections from customers.borrowings.

Three Months Ended March 31,	Three Months Ended March 31,								Three Months Ended March 31,
2019			2018			2019 vs. 2018
2020									2020		2019			2020 vs. 2019
(In millions)	(In millions)								(In millions)
$	(1,068.8	)	$	(677.3	)	$	(391.5	)	(201.9	)	$	(1,068.8	)	$	866.9

Cash used in investing activities ~~increased~~decreased in ~~2019~~2020 compared to ~~2018,~~2019, primarily due to ~~higher~~lower outlays for property, plant and equipment of ~~$347.4~~$601.6 million, ~~mainly related to~~resulting from the completion of construction of Grand Prix, Train ~~7 and Train 8,~~6, and additional processing plants and associated infrastructure in the Permian ~~Basin.~~Basin in 2019. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude gathering system and a ~~$29.4~~$116.0 million ~~increase~~decrease in our contributions to unconsolidated affiliates essentially due to ~~higher construction activities~~the completion of GCX Pipeline ~~partially offset by lower construction activities of Little Missouri 4.~~in 2019.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Source of Financing Activities, net	(In millions)						(In millions)
Distributions							$	(241.9	)	$	(241.3	)
Contributions from (distributions to) noncontrolling interests								(94.5	)		196.8
Debt, including financing costs	$	732.7		$	310.0			132.9			732.7
Contributions from noncontrolling interests		196.8			280.1
Contributions from TRC and General Partner		—			60.0
Distributions		(241.3	)		(228.5	)
Other		(18.6	)		(16.5	)		-			(18.6	)
Net cash provided by (used in) financing activities	$	669.6		$	405.1		$	(203.5	)	$	669.6

In 2020, net cash used in financing activities is primarily due to distributions to TRC, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth projects in 2019. Our debt outstanding increased due to net borrowings under our credit facility, partially offset by repurchases of a portion of our outstanding senior notes.

In 2019, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding, contributions from noncontrolling interests, partially offset by payments of ~~dividends and~~ distributions. The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects

In 2018, we realized a net source of cash from financing activities primarily due to borrowings under the TRP Revolver and contributions from noncontrolling interests, partially offset by the payments of distributions to TRC. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects..

TRC is entitled to receive all available Partnership distributions after payments of preferred distributions each quarter.

The following table details the distributions declared and paid by us during the three months ended March 31, ~~2019:~~2020:

Distributions on our Preferred Units are declared and paid monthly. As of March 31, ~~2019,~~2020, we have 5,000,000 Preferred Units outstanding. For the three months ended March 31, ~~2019,~~2020, $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 15, ~~2019.~~2020.

In April ~~2019,~~2020, 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, ~~2019.~~2020.

Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance ~~revenues, and fund acquisitions of businesses or assets.~~revenues. 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.

The following table details cash outlays for capital projects for the three months ended March 31, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Capital expenditures:
Growth (1)	$	870.0		$	535.6		$	277.0		$	870.0
Maintenance (2)		35.6			22.4			26.8			35.6
Gross capital expenditures		905.6			558.0			303.8			905.6
Transfers of capital expenditures to investment in unconsolidated affiliates		—			16.0
Transfers from materials and supplies inventory to property, plant and equipment		(1.1	)		(0.4	)		(1.7	)		(1.1	)
Change in capital project payables and accruals		38.4			22.3			39.6			38.4
Cash outlays for capital projects	$	942.9		$	595.9		$	341.7		$	942.9

We currently estimate that in ~~2019~~2020 we will invest approximately ~~$2,300~~$700 million to $800 million in ~~net~~ growth capital expenditures, ~~(exclusive~~net of ~~outlays for business acquisitions)~~noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects. ~~Future~~The estimate is reduced from our previously disclosed range of $1.2 billion to $1.3 billion, which represents a forty percent reduction at the midpoint of both ranges, in a response to current market conditions as described under “Recent Developments – Response to Current Market Conditions.” The vast majority of spending is for major ongoing growth capital ~~expenditures may vary significantly based on investment opportunities.~~ projects where the capital is already predominantly spent. We expect that ~~2019 net~~2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $130 million.

Total growth capital expenditures ~~increased~~reduced for the three months ended March 31, ~~2019~~2020 as compared to the three months ended March 31, ~~2018,~~2019, primarily due to lower spending ~~related to construction of~~on growth investments as Grand Prix, Train ~~7 and Train 8,~~6, and additional processing plants and associated infrastructure in the Permian ~~Basin.~~ Basin began full service in 2019. Total maintenance capital expenditures ~~increased~~reduced for the three months ended March 31, ~~2019~~2020 as compared to the three months ended March 31, ~~2018,~~2019, primarily due to ~~our increased asset base and additional infrastructure.~~timing of maintenance projects.

As of March 31, ~~2019,~~2020, there were ~~$56.5~~$47.6 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 ~~Qualitati~~veQualitative 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.

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 energy 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, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through ~~2023~~2024. Market conditions may also impact our ability to enter into future commodity derivative contracts.

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~~commodities as payment for services. The prices of natural gas, NGLs and crude oil 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, ~~2019,~~2020, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and ~~Marketing~~Transportation segment and (iii) natural gas transportation basis risk in our Logistics and ~~Marketing~~Transportation 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 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 fair value of our natural gas and NGL hedges 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 hedges are 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 commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our 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.

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).

To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of March 31, ~~2019~~2020:

	Fair Value			Result of 10% Price Decrease		Result of 10% Price Increase			Fair Value			Result of 10% Price Decrease		Result of 10% Price Increase
Natural gas	$	27.7		$	57.3	$	(1.8	)	$	(11.6	)	$	37.1	$	(59.9	)
NGLs		23.2			59.4		(12.9	)		145.9			172.8		118.8
Crude oil		(4.6	)		12.5		(25.4	)		75.6			88.1		63.0
Total	$	46.3		$	129.2	$	(40.1	)	$	209.9		$	298.0	$	121.9

The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.

Our operating revenues increased (decreased) by ~~$11.8~~$161.4 million and ($~~(38.8) million~~11.8 million) during the three months ended March 31, ~~2019~~2020 and ~~2018,~~2019, 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 ~~asset~~liability position of ~~$112.7~~$6.1 million at December 31, ~~2018~~2019 to a net asset position of ~~$46.3~~$209.9 million at March 31, ~~2019.~~2020. 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.

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, ~~2019,~~2020, 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, ~~2019,~~2020, we had ~~$977.6~~$628.1 million in outstanding variable rate borrowings under the TRP Revolver and the 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 ~~$9.8~~$6.3 million based on our March 31, ~~2019~~2020 debt balances.

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 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 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 ~~$52.7~~$65.4 million as of March 31, ~~2019.~~2020. The range of losses attributable to our individual counterparties as of March 31, ~~2019~~2020 would be between ~~less than $0.1~~$2.5 million and ~~$21.6~~$50.7 million, depending on the counterparty in default.

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 performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring 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 due to bankruptcies or other liquidity issues of counterparties. ~~If an assessment of uncollectible~~Our allowance for doubtful accounts ~~resulted in a 1% reduction of our third-party accounts receivable~~was $0.1 million and $0.0 million as of March 31, ~~2019, our operating income would decrease by $7.5 million~~2020 and December 31, 2019. Changes in the ~~year of~~allowance for doubtful accounts were not material for the ~~assessment.~~three months ended March 31, 2020.

During the three months ended March 31, ~~2019~~2020 and ~~2018,~~2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately ~~12%~~11% and ~~14%~~12% of our consolidated revenues.

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, as of March 31, ~~2019,~~2020, the design and operation of 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.

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, during our most recent fiscal quarter.

~~The~~On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80^th District Court of Harris County, Texas against Targa Channelview LLC, a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

Additional information required for this item is provided in Note 1613 – 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.

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

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of crude oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

Additionally, we have been and may continue to be adversely affected by the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic has reduced economic activity and the related demand for energy commodities. These effects, combined with a period of increased production from major oil producing nations and decreasing availability of crude oil storage, has contributed to a sharp drop in prices in the first half of 2020 and is expected to continue to impact demand over the short-term.

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed

percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

As further discussed in Note 4 – Property, Plant and Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, the global decline in commodity prices due to both demand and supply disruptions was a significant contributing factor to the non-cash impairment charges totaling $2,442.8 million for the three months ended March 31, 2020.

The widespread outbreak of the COVID-19 pandemic or any other public health crisis that impacts the global demand for commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the recent global spread of COVID-19 has caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for crude oil, natural gas and natural gas liquids (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations.

The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Refer to Note 4 – Property, Plant and Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion.

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.

Delaware		65-1295427
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

811 Louisiana St, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)


Title of each class	Trading Symbol(s)	Name of exchange on which registered
9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	NGLS/PA	New York Stock Exchange


~~Title of each class~~	~~Trading Symbol(s)~~	~~Name of exchange on which registered~~
~~9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~	~~NGLS/PA~~	~~New York Stock Exchange~~

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019		4

Consolidated Statements of Operations for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019		5

Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019		6

Consolidated Statements of Changes in Owners' Equity for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019		7

Consolidated Statements of Cash Flows for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019		8

Notes to Consolidated Financial Statements		9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2724

Item 3. Quantitative and Qualitative Disclosures About Market Risk		4340

Item 4. Controls and Procedures		4542

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		4643

Item 1A. Risk Factors		4643

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4644

Item 3. Defaults Upon Senior Securities		4644

Item 4. Mine Safety Disclosures		4644

Item 5. Other Information		4644

Item 6. Exhibits		4745

SIGNATURES

Signatures		4947


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
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
SCOOP	South Central Oklahoma Oil Province
STACK	Sooner Trend, Anadarko, Canadian and Kingfisher

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☑	Smaller reporting company	☐
		Emerging growth company	☐

Balance at December 31, 2018	$	1,983.2
Amortization		(43.0	)
Balance at March 31, 2019	$	1,940.2

Balance at December 31, 2019	$	1,735.0
Impairment		(208.6	)
Amortization		(38.4	)
Balance at March 31, 2020	$	1,488.0

Debt Repurchased	Book Value		Payment			Gain/(Loss)		Write-off of Debt Issuance Costs			Net Gain/(Loss)
5⅛% Senior Notes due 2025	$	8.1	$	(5.3	)	$	2.8	$	-		$	2.8
5⅞% Senior Notes due 2026		7.3		(5.1	)		2.2		-			2.2
5⅜% Senior Notes due 2027		9.9		(7.7	)		2.2		(0.1	)		2.1
6½% Senior Notes due 2027		35.1		(27.1	)		8.0		(0.3	)		7.7
5% Senior Notes due 2028		30.1		(21.5	)		8.6		(0.2	)		8.4
6⅞% Senior Notes due 2029		60.2		(46.6	)		13.6		(0.6	)		13.0
5½% Senior Notes due 2030		12.0		(8.8	)		3.2		(0.1	)		3.1
	$	162.7	$	(122.1	)	$	40.6	$	(1.3	)	$	39.3

	Payments Due By Period
			Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years
	(in millions)

Long-term debt obligations (1)	$	7,225.6	$	-	$	6.5	$	2,623.6	$	4,595.5
Interest on debt obligations (2)		2,605.2		394.9		794.1		645.4		770.8
	$	9,830.8	$	394.9	$	800.6	$	3,269.0	$	5,366.3


(1)	Represents scheduled future maturities of consolidated debt obligations for the periods indicated.


(2)		Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing March 31, 2020 rates for floating debt.

	March 31, 2019		December 31, 2018
Asset retirement obligations	$	63.4	$	55.0
Deferred revenue		174.6		175.5
Operating lease liabilities		17.3		—
Other liabilities		3.0		3.3
Total long-term liabilities	$	258.3	$	233.8

Balance at December 31, 2018	$	175.5
Additions		—
Revenue recognized		(0.9	)
Balance at March 31, 2019	$	174.6

	Balance Sheet Location	March 31, 2019
Right-of-use assets
Operating leases, gross	Other long-term assets	$	25.2
Finance leases, gross	Property, plant and equipment		40.9

Lease liabilities
Current:
Operating leases	Accounts payable and accrued liabilities	$	6.6
Finance leases	Current debt obligations		10.5
Non-current:
Operating leases	Other long-term liabilities		17.3
Finance leases	Long-term debt		27.7

		Three Months Ended March 31, 2019
Lease cost
Operating lease cost	$	1.9
Short-term lease cost		7.6
Variable lease cost		1.3
Finance lease cost
Amortization of right-of-use assets		3.1
Interest expense		0.4
Total lease cost	$	14.3

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases	$	1.9
Operating cash flows for finance leases		0.4
Financing cash flows for finance leases		2.7

	Operating Leases			Finance Leases
Future Minimum Lease Payments Beginning After March 31,
2019	$	7.4		$	11.8
2020		5.6			11.0
2021		5.3			9.2
2022		4.2			8.2
2023		2.4			1.0
Thereafter		1.0			—
Total undiscounted cash flows		25.9			41.2
Less imputed interest		(2.0	)		(3.0	)
Total lease liabilities	$	23.9		$	38.2

	Leases
2019	$	20.5
2020		17.7
2021		14.9
2022		12.6
2023		6.0
Thereafter		1.7
Total payments	$	73.4

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Consideration
Balance, December 31, 2018		$	6.5		$	(310.6	)
	Completion of Permian Acquisition contingent consideration earn-out period		-			308.2
	Unrealized gain/(loss) included in OCI		(3.1	)		-
Balance, March 31, 2019		$	3.4		$	(2.4	)

		2019				2020				2021 and after
Fixed consideration to be recognized as of March 31, 2019		$	394.3			$	463.0			$	3,327.5

		2020				2021				2022 and after
Fixed consideration to be recognized as of March 31, 2020		$	403.7			$	513.5			$	3,226.5

	Three Months Ended March 31, 2020						Three Months Ended March 31, 2019
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)		Gain (Loss)		Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		15.7	$	0.95	$	15.0		12.1	$	0.72		$	8.7
NGL (MMgal)		95.6		0.18		17.5		69.4		0.01			0.5
Crude oil (MBbl)		0.5		12.08		5.5		0.3		(0.04	)		—
					$	38.0						$	9.2

Number		Description

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	Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K ~~(File No. 001-33303)~~ filed December 12, ~~2017)~~2017 (File No. 001-33303)).

3.5	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)).

10.1*	Supplemental Indenture dated February 20, 2020 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.

~~4.2~~10.2*	Supplemental Indenture dated ~~as of January 17, 2019~~February 20, 2020 to Indenture dated May 14, 2013, among the ~~Issuers,~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2019 (File No. 001-33303)).~~Association.

~~4.3~~10.3*	~~Registration Rights Agreement~~Supplemental Indenture dated ~~as of January 17, 2019~~February 20, 2020 to Indenture dated September 14, 2015, among the ~~Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to~~Guaranteeing Subsidiary, Targa Resources Partners ~~LP’s Current Report on Form 8-K filed January 23, 2019 (File No. 001-33303)).~~LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

~~4.4~~10.4*	~~Registration Rights Agreement~~Supplemental Indenture dated ~~as of January 17, 2019~~February 20, 2020 to Indenture dated October 6, 2016, among the ~~Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.3 to~~Guaranteeing Subsidiary, Targa Resources Partners ~~LP’s Current Report on Form 8-K filed January 23, 2019 (File No. 001-33303)).~~LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

~~10.1~~10.5*	~~Purchase Agreement~~Supplemental Indenture dated ~~as of January 10, 2019,~~February 20, 2020 to Indenture dated October 17, 2017, among the ~~Issuers,~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and ~~Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers.~~U.S. Bank National Association.

~~10.2+~~10.6*	Supplemental Indenture dated February 20, 2020 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.7*	Supplemental Indenture dated February 20, 2020 to Indenture dated January 17, 2019, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.8*	Supplemental Indenture dated February 20, 2020 to Indenture dated November 27, 2019, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.9+	Targa Resources Corp. ~~2019~~2020 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January ~~22, 2019~~23, 2020 (File No. 001-33303)).

~~10.3+~~	Indemnification Agreement by and between Targa Resources Corp. and Julie Boushka, dated February 22, 2017 (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed March 5, 2019 (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.~~

Number		Description

32.1**10.13	Ninth Amendment to Receivables Purchase Agreement, dated April 22, 2020, by and among Targa Receivables LLC, as seller, Targa Resources Partners LP, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 24, 2020 (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*	Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*	Inline XBRL Taxonomy Extension Schema Document

101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF101.LAB	Inline XBRL Taxonomy Extension ~~Definition~~Label Linkbase Document

101.LAB101.PRE	Inline XBRL Taxonomy Extension ~~Label~~Presentation Linkbase Document

101.PRE101.DEF	Inline XBRL Taxonomy Extension ~~Presentation~~Definition Linkbase Document

104*	The cover page from this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, formatted in Inline XBRL (included with Exhibit 101 attachments).

	Targa Resources Partners LP

	By:	Targa Resources GP LLC,
		its general partner

Date: May ~~8, 2019~~7, 2020	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)