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 ~~November~~May 1, ~~2019,~~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:

Additionally, while we have not been previously materially impacted by prior outbreaks of illnesses, pandemics or other public health crises, there are potential risks to us from 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, which 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.

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 ~~September 30, 2019~~March 31, 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:

					September 30, 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				$	294.9		$	203.3		Cash and cash equivalents					$	340.2	$	291.1
Trade receivables, net of allowances of $0.0 and $0.1 million at September 30, 2019 and December 31, 2018						742.9			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					210.9			164.7		Inventories						100.2		161.5
Assets from risk management activities	Assets from risk management activities					140.1			115.3		Assets from risk management activities						199.7		103.3
Other current assets	Other current assets					43.4			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					1,432.2			1,379.9		Total current assets						1,124.7		1,603.0
Property, plant and equipment						19,589.1			17,213.8
Accumulated depreciation and amortization						(4,892.4	)		(4,285.5	)
Property, plant and equipment, net	Property, plant and equipment, net					14,696.7			12,928.3		Property, plant and equipment, net						12,411.3		14,549.0
Intangible assets, net	Intangible assets, net					1,854.4			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					60.0			34.1		Long-term assets from risk management activities						82.2		35.5
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates					718.5			490.5		Investments in unconsolidated affiliates						736.8		738.7
Other long-term assets	Other long-term assets					49.9			27.5		Other long-term assets						80.3		83.3
Total assets	Total assets				$	18,858.3		$	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				$	1,234.8		$	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.					194.0			187.4		Accounts payable to Targa Resources Corp.						161.0		193.8
Liabilities from risk management activities	Liabilities from risk management activities					83.5			33.6		Liabilities from risk management activities						41.8		104.1
Current debt obligations	Current debt obligations					258.0			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					1,770.3			2,885.8		Total current liabilities						1,307.8		1,970.2
Long-term debt	Long-term debt					6,844.7			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					46.1			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					261.7			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	Issued		Outstanding			120.6			120.6		Series A preferred limited partners	Issued		Outstanding			120.6		120.6
September 30, 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	Issued		Outstanding			5,437.1			6,227.2		Common limited partners	Issued		Outstanding			2,803.6		5,022.7
September 30, 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	Issued		Outstanding			786.4			802.6		General partner	Issued		Outstanding			732.6		778.0
September 30, 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)						186.6			124.9		Accumulated other comprehensive income (loss)						221.5		122.5
						6,530.7			7,275.3								3,878.3		6,043.8
Noncontrolling interests						3,380.9			1,270.8		Noncontrolling interests						3,225.6		3,401.5
Total owners' equity	Total owners' equity					9,911.6			8,546.1		Total owners' equity						7,103.9		9,445.3
Total liabilities and owners' equity	Total liabilities and owners' equity				$	18,858.3		$	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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(Unaudited)												(Unaudited)
	(In millions)												(In millions)
Revenues:
Sales of commodities	$	1,594.2		$	2,654.1		$	5,254.8		$	6,981.4		$	1,779.7		$	1,976.5
Fees from midstream services		308.3			332.3			942.4			904.9			269.2			322.9
Total revenues		1,902.5			2,986.4			6,197.2			7,886.3			2,048.9			2,299.4
Costs and expenses:
Product purchases		1,328.1			2,383.5			4,415.7			6,229.7			1,188.3			1,726.0
Operating expenses		200.2			194.9			600.7			538.7			194.6			190.2
Depreciation and amortization expense		244.3			206.3			718.9			607.1			239.1			237.4
General and administrative expense		65.6			59.3			212.3			165.0			57.0			77.7
Impairment of long-lived assets														2,442.8			—
Other operating (income) expense		18.4			61.8			21.7			15.7			1.1			3.4
Income (loss) from operations		45.9			80.6			227.9			330.1			(2,074.0	)		64.7
Other income (expense):
Interest expense, net		(84.2	)		(75.7	)		(229.2	)		(113.3	)		(93.8	)		(75.4	)
Equity earnings (loss)		10.0			3.0			15.9			6.4			20.6			2.8
Gain (loss) from financing activities		—			—			(1.4	)		(1.3	)		39.3			(1.4	)
Gain (loss) from sale of equity-method investment		65.8			—			65.8			—
Change in contingent considerations		—			(16.6	)		(8.8	)		(12.1	)		—			(9.7	)
Income (loss) before income taxes		37.5			(8.7	)		70.2			209.8			(2,107.9	)		(19.0	)
Income tax (expense) benefit		—			—			—			—			—			—
Net income (loss)		37.5			(8.7	)		70.2			209.8			(2,107.9	)		(19.0	)
Less: Net income (loss) attributable to noncontrolling interests		76.6			9.7			144.3			32.0			(85.3	)		11.4
Net income (loss) attributable to Targa Resources Partners LP	$	(39.1	)	$	(18.4	)	$	(74.1	)	$	177.8		$	(2,022.6	)	$	(30.4	)

Net income attributable to preferred limited partners	$	2.8		$	2.8		$	8.4		$	8.4		$	2.8		$	2.8
Net income (loss) attributable to general partner		(0.9	)		(0.4	)		(1.7	)		3.4			(40.6	)		(0.7	)
Net income (loss) attributable to common limited partners		(41.0	)		(20.8	)		(80.8	)		166.0			(1,984.8	)		(32.5	)
Net income (loss) attributable to Targa Resources Partners LP	$	(39.1	)	$	(18.4	)	$	(74.1	)	$	177.8		$	(2,022.6	)	$	(30.4	)

	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2019			2018			2019			2018				2020			2019
	(Unaudited)													(Unaudited)
	(In millions)													(In millions)
Net income (loss)	$	37.5		$	(8.7	)	$	70.2		$	209.8		Net income (loss)	$	(2,107.9	)	$	(19.0	)
Other comprehensive income (loss):													Other comprehensive income (loss):
Commodity hedging contracts:													Commodity hedging contracts:
Change in fair value		118.2			(139.6	)		167.8			(178.0	)	Change in fair value		158.9			(38.8	)
Settlements reclassified to revenues		(41.5	)		23.9			(106.1	)		58.3		Settlements reclassified to revenues		(59.9	)		(21.3	)
Other comprehensive income (loss)		76.7			(115.7	)		61.7			(119.7	)	Other comprehensive income (loss)		99.0			(60.1	)
Comprehensive income (loss)		114.2			(124.4	)		131.9			90.1		Comprehensive income (loss)		(2,008.9	)		(79.1	)
Less: Comprehensive income (loss) attributable to noncontrolling interests		76.6			9.7			144.3			32.0		Less: Comprehensive income (loss) attributable to noncontrolling interests		(85.3	)		11.4
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	37.6		$	(134.1	)	$	(12.4	)	$	58.1		Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(1,923.6	)	$	(90.5	)

Accumulated

Limited

Limited

General

Other

Non-

Partner

Partner

Partner

Comprehensive

controlling

Preferred

Amount

Common

Amount

Units

Amount

Income (Loss)

Interests

Total

(Unaudited)

(In millions, except units in thousands)

Balance, June 30, 2018

5,000

$
120.6

275,168

$
6,322.2

5,629

$
804.5

$
(49.9
)

$
911.8

$
8,109.2

Contributions from Targa Resources Corp.

—

—

—

450.6

—

9.2

—

—

459.8

Acquisition of related party

—

—

—

—

—

—

—

—

—

Purchase of noncontrolling interests in subsidiaries, net

—

—

—

—

—

—

—

—

—

Distributions to noncontrolling interests

—

—

—

—

—

—

—

(17.7
)

(17.7
)
Contributions from noncontrolling interests

—

—

—

—

—

—

—

164.4

164.4

Other comprehensive income (loss)

—

—

—

—

—

—

(115.8
)

—

(115.8
)
Net income (loss)

—

2.8

—

(20.8
)

—

(0.4
)

—

9.7

(8.7
)
Distributions

—

(2.8
)

—

(226.5
)

—

(4.6
)

—

—

(233.9
)
Balance, September 30, 2018

5,000

$
120.6

275,168

$
6,525.5

5,629

$
808.7

$
(165.7
)

$
1,068.2

$
8,357.3

																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
Contributions from Targa Resources Corp.		—		—			—		196.0			—		4.0			—		—			200.0
Sale of ownership interests in subsidiaries		—		—			—		(10.5	)		—		(0.2	)		—		1,619.7			1,609.0
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		—		—			—		—			—		—			—		(172.6	)		(172.6	)		—		—			—		—			—		—			—		(101.2	)		(101.2	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—		518.7			518.7			—		—			—		—			—		—			—		10.6			10.6
Other comprehensive income (loss)		—		—			—		—			—		—			61.7		—			61.7			—		—			—		—			—		—			99.0		—			99.0
Net income (loss)		—	8.4				—		(80.8	)		—		(1.7	)		—		144.3			70.2			—	2.8				—		(1,984.8	)		—		(40.6	)		—		(85.3	)		(2,107.9	)
Distributions		—		(8.4	)		—		(894.8	)		—		(18.3	)		—		—			(921.5	)		—		(2.8	)		—		(234.3	)		—		(4.8	)		—		—			(241.9	)
Balance, September 30, 2019		5,000	$	120.6			275,168	$	5,437.1			5,629	$	786.4		$	186.6	$	3,380.9		$	9,911.6
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.		—		—			—		529.2			—		10.8			—			—			540.0
Acquisition of related party		—		—			—		—			—		—			—			1.1			1.1
Purchase of noncontrolling interests in subsidiaries, net		—		—			—		—			—		—			—			(0.1	)		(0.1	)
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		—		—			—		—			—		—			—			(51.5	)		(51.5	)		—		—			—		—			—		—			—			(18.6	)		(18.6	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			611.6			611.6			—		—			—		—			—		—			—			196.8			196.8
Other comprehensive income (loss)		—		—			—		—			—		—			(119.7	)		—			(119.7	)		—		—			—		—			—		—			(60.1	)		—			(60.1	)
Net income (loss)		—		8.4			—		166.0			—		3.4			—			32.0			209.8			—		2.8			—		(32.5	)		—		(0.7	)		—			11.4			(19.0	)
Distributions		—		(8.4	)		—		(670.0	)		—		(13.7	)		—			—			(692.1	)		—		(2.8	)		—		(233.7	)		—		(4.8	)		—			—			(241.3	)
Balance, September 30, 2018		5,000	$	120.6			275,168	$	6,525.5			5,629	$	808.7		$	(165.7	)	$	1,068.2		$	8,357.3
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

		Nine Months Ended September 30,							Three Months Ended March 31,
		2019			2018				2020			2019
	(Unaudited)							(Unaudited)
	(In millions)							(In millions)
Cash flows from operating activities
Net income (loss)		$	70.2		$	209.8			$	(2,107.9	)	$	(19.0	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense			6.8			6.8				2.5			2.4
Depreciation and amortization expense			718.9			607.1				239.1			237.4
Impairment of long-lived assets										2,442.8			—
Accretion of asset retirement obligations			3.7			2.8				0.7			1.0
Increase (decrease) in redemption value of mandatorily redeemable preferred interests			—			(66.3	)
Equity (earnings) loss of unconsolidated affiliates			(15.9	)		(6.4	)			(20.6	)		(2.8	)
Distributions of earnings received from unconsolidated affiliates			26.0			16.0				21.1			4.8
Risk management activities			100.8			9.6				(115.5	)		7.2
(Gain) loss on sale or disposition of assets			3.6			14.3				0.6			3.2
Write-down of assets			17.9			—
(Gain) loss from financing activities			1.4			1.3				(39.3	)		1.4
(Gain) loss from sale of equity-method investment			(65.8	)		—
Change in contingent considerations			8.8			12.1				—			9.7
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets			108.0			(221.7	)			422.9			83.9
Inventories			(89.7	)		(16.6	)			62.3			(60.6	)
Accounts payable and other liabilities			2.7			374.7				(454.2	)		39.0
Net cash provided by operating activities			897.4			943.5				454.5			307.6
Cash flows from investing activities
Outlays for property, plant and equipment			(2,433.8	)		(2,033.6	)			(341.7	)		(942.9	)
Proceeds from sale of assets			2.7			71.5
Proceeds from sale of business and assets										134.8			0.5
Investments in unconsolidated affiliates			(243.7	)		(223.7	)			(1.4	)		(117.4	)
Proceeds from sale of equity-method investment			70.3			—
Return of capital from unconsolidated affiliates			1.1			2.2				2.8			—
Other, net			(16.3	)		(9.2	)			3.6			(9.0	)
Net cash used in investing activities			(2,619.7	)		(2,192.8	)			(201.9	)		(1,068.8	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facility			2,180.0			950.0				790.0			750.0
Repayments of credit facility			(2,050.0	)		(970.0	)			(430.0	)		(780.0	)
Proceeds from borrowings under accounts receivable securitization facility			770.0			440.0				130.0			378.0
Repayments of accounts receivable securitization facility			(804.0	)		(500.0	)			(231.9	)		(350.4	)
Proceeds from issuance of senior notes			1,500.0			1,000.0				—			1,500.0
Redemption of senior notes			(749.4	)		—				(122.1	)		(749.4	)
Principal payments of finance leases			(8.5	)		—				(3.1	)		(2.7	)
Costs incurred in connection with financing arrangements			(25.1	)		(15.8	)			—			(12.8	)
Payment of contingent consideration			(317.1	)		—
Sale of ownership interests in subsidiaries			1,619.7			(0.1	)
Contributions from general partner			4.0			10.8
Contributions from TRC			196.0			529.2
Contributions from noncontrolling interests			518.7			611.6				10.6			196.8
Distributions to noncontrolling interests			(98.9	)		(51.5	)			(105.1	)		(18.6	)
Distributions to unitholders			(921.5	)		(692.1	)			(241.9	)		(241.3	)
Net cash provided by financing activities			1,813.9			1,312.1
Net cash provided by (used in) financing activities										(203.5	)		669.6
Net change in cash and cash equivalents			91.6			62.8				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		$	294.9		$	187.5			$	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/PA.”

See Note 2016 – 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 ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 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 ~~nine~~three months ended ~~September 30, 2019.~~March 31, 2020.

In ~~February 2016,~~August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) ~~2016-02,~~ 2018-13, ~~Leases~~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 0tnot 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.

~~Our lease arrangements may include variable lease payments based~~Accounting Policy Updates

Estimated losses on accounts receivable are provided through an ~~index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we~~allowance for doubtful accounts. 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 measurementallowance for doubtful accounts through various procedures, including extensive review of our ~~right-of-use asset~~trade receivable balances by counterparty, assessing economic events and ~~liability, provided we determine that we are reasonably certain to exercise~~conditions, our historical experience with counterparties, the ~~option.~~

~~In February 2019, we announced an extension~~counterparty’s financial condition and the amount and age of the Grand Prix NGL Pipeline (“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. ~~We present Train 7 on a consolidated basis in our consolidated financial statements.~~

~~On April 3, 2019, we closed on the sale of a~~ 45~~% interest in Targa Badlands LLC (“Targa Badlands”), 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. Future growth capital of Targa Badlands is expected to be funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Once Blackstone receives funds sufficient to meet a predetermined fixed return on their invested capital, their interest will convert to a 7.5% equity interest in Targa Badlands, and it will no longer have a priority right on MQDs. Additionally, upon a sale of Targa Badlands, Blackstone’s capital contributions would have a liquidation preference equal to a predetermined fixed return on their invested capital.

~~After~~ the seventh anniversary of the closing date or upon the occurrence of certain triggering events, we have the option to acquire all of Blackstone’s interest in Targa Badlands for a purchase price payable to Blackstone based on their liquidation preference after taking into account all prior distributions to Blackstone, plus a set percentage on a multiple of the trailing twelve-month EBITDA of Targa Badlands. Targa will continue to control the management of Targa Badlands pending the occurrence of certain triggering events, including if Blackstone has not received funds sufficient to meet its liquidation preference and Targa has not exercised its purchase right to acquire Blackstone’s interest by April 3, 2029.past due accounts.

We ~~continue~~continuously evaluate our ability to becollect amounts owed to us. Receivables are considered past due if full payment is not received by the ~~operator~~contractual due date. These procedures also include performing account reconciliations, dispute resolution and payment confirmation. We may involve our legal counsel to pursue the recovery of ~~Targa Badlands and hold majority governance rights. As a result, we continue to present Targa~~ ~~Badlands~~ ~~on a consolidated basis in our consolidated financial statements and~~ ~~Blackstone’s contributions are reflected as noncontrolling interests~~.defaulted trade receivables.

~~In November 2019, we executed agreements~~As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to ~~sell~~ our crude gathering and storage business in the Permian Delaware for approximately $135 million. Subject to customary regulatory approvals and closing conditions, the sale is expected to close in the fourth quarter of 2019.

We have also engaged Jefferies LLC to evaluate the potential divestiture of our crude gathering business in the Permian Midland, which includes crude gathering and storage assets. The potential divestiture is predicated on third party valuations adequately capturing our forward growth expectations for the assets, and no assurance canallowance may be ~~made that a sale will be consummated.~~required.

	September 30, 2019			December 31, 2018			Estimated Useful Lives (In Years)	March 31, 2020			December 31, 2019			Estimated Useful Lives (In Years)
Gathering systems	$	8,767.6		$	7,547.9		5 to 20	$	9,027.1		$	8,976.8		5 to 20
Processing and fractionation facilities		4,961.3			4,001.0		5 to 25		5,363.7			5,137.0		5 to 25
Terminaling and storage facilities		1,459.1			1,138.7		5 to 25		1,498.3			1,495.5		5 to 25
Transportation assets		2,221.9			445.1		10 to 50		2,313.1			2,292.4		10 to 50
Other property, plant and equipment		302.0			334.3		3 to 25		297.8			183.9		3 to 25
Land		154.4			144.3		—		159.2			159.7		—
Construction in progress		1,675.9			3,602.5		—		1,424.9			1,576.5		—
Finance lease right-of-use assets		46.9			—				51.2			48.8
Property, plant and equipment		19,589.1			17,213.8				20,135.3			19,870.6
Accumulated depreciation and amortization		(4,892.4	)		(4,285.5	)
Accumulated depreciation, amortization and impairment									(7,724.0	)		(5,321.6	)
Property, plant and equipment, net	$	14,696.7		$	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		(882.2	)		(753.4	)
Accumulated amortization and impairment									(1,155.5	)		(908.5	)
Intangible assets, net	$	1,854.4		$	1,983.2			$	1,488.0		$	1,735.0

During the preparation of the Company's ~~first quarter 2019~~ 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 ~~period of identification, resulting~~three months ended March 31, 2019. This adjustment resulted in a one-time $12.5 million overstatement of depreciation ~~expense.~~expense during the three months ended March 31, 2019.

During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, depreciation expense was ~~$201.4~~$200.7 million and ~~$590.1~~$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 ~~three~~first quarter of 2020, global commodity prices declined due to factors that significantly impacted both demand and ~~nine~~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 ~~September 30, 2018, depreciation expense was $161.7 million~~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 ~~$470.9 million.~~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.

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 recover the 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.

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 venture owners and have capacity lease agreements with their joint venture owners, which cover costs of operations (excluding depreciation and amortization). ~~On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures.~~

~~During the third quarter of 2019,~~ we closed on the sale of an equity-method investment for $70.3 million that resulted in the recognition of a gain of $65.8 million during the three months ended September 30, 2019, which is reported as part of Other (income) expense.

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

	Balance at December 31, 2018		Equity Earnings (Loss)			Cash Distributions			Disposition			Contributions		Balance at September 30, 2019		Balance at December 31, 2019		Equity Earnings (Loss)			Distributions			Contributions		Balance at March 31, 2020
GCX (1)	$	211.6	$	8.9		$	(5.3	)	$	—		$	210.4	$	425.6	$	447.5	$	16.4		$	(21.0	)	$	1.4	$	444.3
Little Missouri 4																	103.7		3.3			—			—		107.0
T2 Eagle Ford (2)		99.0		(7.5	)		—			—			—		91.5		89.6		(2.2	)		(0.9	)		—		86.5
Little Missouri 4		67.3		0.1			—			—			33.0		100.4
T2 LaSalle (2)		49.3		(3.5	)		—			—			—		45.8		44.8		(1.2	)		(0.4	)		—		43.2
GCF		40.3		14.0			(14.7	)		—			—		39.6		37.2		2.4			(1.6	)		—		38.0
Cayenne		16.6		5.4			(6.7	)		—			0.3		15.6		15.9		1.9			—			—		17.8
Agua Blanca		6.4		(1.5	)		(0.4	)		(4.5	)		—		—
Total	$	490.5	$	15.9		$	(27.1	)	$	(4.5	)	$	243.7	$	718.5	$	738.7	$	20.6		$	(23.9	)	$	1.4	$	736.8

	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Commodities	$	612.0	$	721.9	$	318.6	$	683.6
Other goods and services		359.6		474.5		264.1		311.5
Interest		91.6		79.4		107.5		125.4
Permian Acquisition contingent consideration		—		308.2
Income and other taxes		79.5		45.4		36.2		62.0
Accrued distributions to noncontrolling interests		73.8		—		87.8		91.7
Other		18.3		7.5		10.2		9.5
	$	1,234.8	$	1,636.9	$	824.4	$	1,283.7

Accounts payable and accrued liabilities includes ~~$15.3~~$9.4 million and ~~$52.2~~$21.6 million of liabilities to creditors to whom we have issued checks that remained outstanding as of ~~September 30, 2019~~March 31, 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 included the fair value of the contingent consideration in accounts payable and accrued liabilities as of December 31, 2018. The contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019.

	September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Current:
Accounts receivable securitization facility, due December 2019 (1)	$	246.0		$	280.0
Senior unsecured notes, 4⅛% fixed rate, due November 2019		—			749.4
		246.0			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		12.0			—			12.5			12.2
Current debt obligations		258.0			1,027.9			280.6			382.2

Long-term:
Senior secured revolving credit facility, variable rate, due June 2023 (2)		830.0			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
		6,858.5			5,228.5			7,225.8			7,028.5
Debt issuance costs, net of amortization		(40.7	)		(31.1	)		(46.2	)		(49.1	)
Finance lease liabilities		26.9			—			25.2			25.8
Long-term debt		6,844.7			5,197.4			7,204.8			7,005.2
Total debt obligations	$	7,102.7		$	6,225.3		$	7,485.4		$	7,387.4
Irrevocable standby letters of credit outstanding (2)	$	73.8		$	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 ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:

As of ~~September 30, 2019,~~March 31, 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~~repurchased on the open market a portion of our outstanding senior notes as follows:

On April 22, 2020, we amended our Securitization Facility to decrease the facility size from $400.0 million ~~of 6½% Senior Notes due July 2027~~to $250.0 million to more closely align with expectations for borrowing capacity given current commodity prices and ~~$750.0 million of 6~~⅞~~% Senior Notes due January 2029, resulting in total net proceeds of $1,486.6 million. The net proceeds from~~to extend the ~~issuance were used~~facility termination date to redeem in full our 4⅛% Senior Notes due 2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment of borrowings under our credit facilities.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.

Other long-term liabilities isare comprised of deferred revenue, asset retirement obligations and 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 ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, was ~~$173.0~~$171.4 million and ~~$175.5~~$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 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 expense, net 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 September 30, 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 ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:

All capital contributions to us continue to be allocated 98% to the limited partner and 2% to our general partner; however, 0 units will be issued for those contributions. During the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, TRC ~~made total~~did 0t make any contributions ~~of $10.0 million and $200.0 million~~ 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 ~~and $8.4 million~~ of distributions to the holders of Preferred Units (“Preferred Unitholders”) for the three ~~and nine~~ months ended ~~September 30, 2019.~~March 31, 2020.

In ~~October 2019,~~April 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 ~~November~~May 15, ~~2019.~~

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 ~~September 30, 2019,~~March 31, 2020, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2019		2020		2021		2022		2023		2024		Instrument	Unit	2020		2021		2022		2023		2024
Natural Gas	Swaps	MMBtu/d		172,254		96,130		85,151		7,500		-		-	Swaps	MMBtu/d		167,230		165,121		86,100		20,000		-
Natural Gas	Basis Swaps	MMBtu/d		398,098		352,260		339,360		200,000		200,000		40,000	Basis Swaps	MMBtu/d		436,064		399,360		268,363		220,000		50,000
NGL	Swaps	Bbl/d		30,468		20,305		8,396		3,236		-		-	Swaps	Bbl/d		26,012		14,151		8,991		-		-
NGL	Futures	Bbl/d		29,620		15,495		-		-		-		-	Futures	Bbl/d		15,527		3,521		-		-		-
NGL	Options	Bbl/d		410		-		-		-		-		-
Condensate	Swaps	Bbl/d		4,170		4,140		3,154		1,110		-		-	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 September 30, 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	$	138.2	$	(11.4	)	$	112.5	$	(18.9	)	Current	$	190.9	$	15.6	$	102.1	$	11.6
	Long-term		56.6		(1.1	)		31.6		(1.5	)	Long-term		69.3		24.9		33.7		6.4
Total derivatives designated as hedging instruments		$	194.8	$	(12.5	)	$	144.1	$	(20.4	)		$	260.2	$	40.5	$	135.8	$	18.0
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	1.9	$	(72.1	)	$	2.8	$	(14.7	)	Current	$	8.8	$	26.2	$	1.2	$	92.5
	Long-term		3.4		(45.0	)		2.5		(1.6	)	Long-term		12.9		5.3		1.8		34.4
Total derivatives not designated as hedging instruments		$	5.3	$	(117.1	)	$	5.3	$	(16.3	)		$	21.7	$	31.5	$	3.0	$	126.9
Total current position		$	140.1	$	(83.5	)	$	115.3	$	(33.6	)		$	199.7	$	41.8	$	103.3	$	104.1
Total long-term position			60.0		(46.1	)		34.1		(3.1	)			82.2		30.2		35.5		40.8
Total derivatives		$	200.1	$	(129.6	)	$	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
September 30, 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	$	103.9	$	(69.5	)	$	(25.2	)	$	62.5	$	(53.3	)	Counterparties with offsetting positions or collateral	$	157.2	$	(41.8	)	$	(11.9	)	$	120.8	$	(17.3	)
	Counterparties without offsetting positions - assets		36.2		-			-			36.2		-		Counterparties without offsetting positions - assets		42.5		-			-			42.5		-
	Counterparties without offsetting positions - liabilities		-		(14.0	)		-			-		(14.0	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			140.1		(83.5	)		(25.2	)		98.7		(67.3	)			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		47.1		(46.1	)		-			32.1		(31.1	)	Counterparties with offsetting positions or collateral		61.4		(30.2	)		-			31.4		(0.2	)
	Counterparties without offsetting positions - assets		12.9		-			-			12.9		-		Counterparties without offsetting positions - assets		20.8		-			-			20.8		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-		Counterparties without offsetting positions - liabilities		-		-			-			-		-
			60.0		(46.1	)		-			45.0		(31.1	)			82.2		(30.2	)		-			52.2		(0.2	)
Total Derivatives	Total Derivatives														Total Derivatives
	Counterparties with offsetting positions or collateral		151.0		(115.6	)		(25.2	)		94.6		(84.4	)	Counterparties with offsetting positions or collateral		218.6		(72.0	)		(11.9	)		152.2		(17.5	)
	Counterparties without offsetting positions - assets		49.1		-			-			49.1		-		Counterparties without offsetting positions - assets		63.3		-			-			63.3		-
	Counterparties without offsetting positions - liabilities		-		(14.0	)		-			-		(14.0	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
		$	200.1	$	(129.6	)	$	(25.2	)	$	143.7	$	(98.4	)		$	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 brokers that clear the hedges through an exchange. We maintain a margin deposit with the 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 ~~$70.5~~$209.9 million as of ~~September 30, 2019.~~March 31, 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 September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
Hedging Relationships	2019		2018			2019		2018			2020		2019
Commodity contracts	$	118.2	$	(139.6	)	$	167.8	$	(178.0	)	$	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 September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
Location of Gain (Loss)	2019		2018			2019		2018			2020		2019
Revenues	$	41.5	$	(23.9	)	$	106.1	$	(58.3	)	$	59.9	$	21.3

Based on valuations as of ~~September 30, 2019,~~March 31, 2020, we expect to reclassify commodity hedge-related deferred gains of ~~$182.2~~$218.3 million included in accumulated other comprehensive income into earnings before income taxes through the end of ~~2022,~~2023, with ~~$126.7~~$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 ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, the unrealized mark-to-market ~~losses~~gains are primarily attributable to ~~unfavorable~~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 September 30,						Nine Months Ended September 30,						Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2019			2018			2019			2018			Derivatives	2020		2019
Commodity contracts	Revenue	$	(103.3	)	$	(1.1	)	$	(113.8	)	$	(14.1	)	Revenue	$	100.0	$	(9.5	)

See Note 1411 – Fair Value Measurements and Note 2016 – 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 ~~September 30, 2019,~~March 31, 2020, a net asset position of ~~$70.5~~$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 ~~$34.0~~$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 ~~$175.4~~$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:

			September 30, 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)		$	197.5		$	197.5		$	—		$	196.4		$	1.1	Assets from commodity derivative contracts (1)		$	277.8		$	277.8		$	—		$	277.8		$	—
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			127.0			127.0			—			127.0			—	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			294.9			294.9			—			—			—	Cash and cash equivalents			340.2			340.2			—			—			—
TRP Revolver	TRP Revolver			830.0			830.0			—			830.0			—	TRP Revolver			360.0			360.0			—			360.0			—
Senior unsecured notes	Senior unsecured notes			6,028.5			6,310.6			—			6,310.6			—	Senior unsecured notes			6,865.8			5,742.7			—			5,742.7			—
Accounts receivable securitization facility				246.0			246.0			—			246.0			—
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				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 ~~September 30, 2019,~~March 31, 2020, we had 100 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 TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3. ~~The Permian Acquisition contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1~~ million payment in May 2019. See Note 8 – Accounts Payable and Accrued Liabilities for additional discussion of the Permian Acquisition contingent consideration. 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 4 – 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.

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, 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.

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 19 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 2016 – Segment Information.

	Nine Months Ended September 30,					Three Months Ended March 31,
	2019			2018		2020			2019
Cash:
Interest paid, net of capitalized interest (1)	$	216.6		$	140.5	$	109.7		$	61.2
Income taxes paid, net of refunds		(1.7	)		0.2		0.1			0.3
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment	$	(150.6	)	$	283.9	$	(39.6	)	$	(38.4	)
Transfers from materials and supplies inventory to property, plant and equipment		21.7			8.9		1.7			1.1
Non-cash financing activities:
Accrued distributions to noncontrolling interests	$	73.8		$	—
Non-cash balance sheet movements related to assets held for sale:
Working capital	$	—		$	12.6
Property, plant and equipment, net		—			151.4
Lease liabilities arising from recognition of right-of-use assets:
Operating lease	$	6.7		$	—
Finance lease		8.0			—
Impact of accrued distributions on noncontrolling interests						$	(3.9	)	$	—

We operate in 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 September 30, 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	$	254.4	$	1,403.1	$	(63.3	)	$	—		$	1,594.2	$	243.8	$	1,419.6	$	116.3	$	—		$	1,779.7
Fees from midstream services		173.0		135.3		—			—			308.3		118.2		151.0		—		—			269.2
		427.4		1,538.4		(63.3	)		—			1,902.5		362.0		1,570.6		116.3		—			2,048.9
Intersegment revenues
Sales of commodities		534.0		34.9		—			(568.9	)		—		443.2		56.5		—		(499.7	)		—
Fees from midstream services		1.9		7.4		—			(9.3	)		—		1.7		8.2		—		(9.9	)		—
		535.9		42.3		—			(578.2	)		—		444.9		64.7		—		(509.6	)		—
Revenues	$	963.3	$	1,580.7	$	(63.3	)	$	(578.2	)	$	1,902.5	$	806.9	$	1,635.3	$	116.3	$	(509.6	)	$	2,048.9
Operating margin	$	208.6	$	228.9	$	(63.3	)	$	—		$	374.2	$	255.7	$	294.0	$	116.3	$	—		$	666.0
Other financial information:
Total assets (1)	$	12,172.4	$	6,475.0	$	157.0		$	53.9		$	18,858.3	$	9,403.7	$	6,347.7	$	16.3	$	155.6		$	15,923.3
Goodwill	$	46.6	$	—	$	—		$	—		$	46.6	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	230.3	$	301.2	$	—		$	10.8		$	542.3	$	116.1	$	177.9	$	—	$	9.8		$	303.8

	Nine Months Ended September 30, 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	$	835.3	$	6,188.3	$	(42.2	)	$	—		$	6,981.4	$	256.9	$	1,726.8	$	(7.2	)	$	—		$	1,976.5
Fees from midstream services		536.8		368.1		—			—			904.9		199.9		123.0		—			—			322.9
		1,372.1		6,556.4		(42.2	)		—			7,886.3		456.8		1,849.8		(7.2	)		—			2,299.4
Intersegment revenues
Sales of commodities		2,848.9		147.0		—			(2,995.9	)		—		822.8		38.4		—			(861.2	)		—
Fees from midstream services		5.4		24.3		—			(29.7	)		—		1.9		5.5		—			(7.4	)		—
		2,854.3		171.3		—			(3,025.6	)		—		824.7		43.9		—			(868.6	)		—
Revenues	$	4,226.4	$	6,727.7	$	(42.2	)	$	(3,025.6	)	$	7,886.3	$	1,281.5	$	1,893.7	$	(7.2	)	$	(868.6	)	$	2,299.4
Operating margin	$	718.4	$	441.7	$	(42.2	)	$	—		$	1,117.9	$	238.3	$	152.1	$	(7.2	)	$	—		$	383.2
Other financial information:
Total assets (1)	$	11,331.5	$	5,019.0	$	64.2		$	111.8		$	16,526.5	$	11,798.2	$	5,644.9	$	3.6		$	84.3		$	17,531.0
Goodwill	$	256.6	$	—	$	—		$	—		$	256.6	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	1,008.2	$	1,229.9	$	—		$	72.3		$	2,310.4	$	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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020		2019
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	305.3		$	451.9		$	934.2		$	1,338.5		$	273.3	$	411.3
NGL		1,160.5			2,063.2			3,752.4			5,254.4			1,161.0		1,396.6
Condensate and crude oil		178.7			95.7			488.4			286.1			135.7		137.7
Petroleum products		11.5			68.2			87.5			176.0			49.8		19.1
		1,656.0			2,679.0			5,262.5			7,055.0			1,619.8		1,964.7
Non-customer revenue:
Derivative activities - Hedge		41.5			(23.8	)		106.1			(59.6	)		59.9		21.3
Derivative activities - Non-hedge (1)		(103.3	)		(1.1	)		(113.8	)		(14.0	)		100.0		(9.5	)
		(61.8	)		(24.9	)		(7.7	)		(73.6	)		159.9		11.8
Total sales of commodities		1,594.2			2,654.1			5,254.8			6,981.4			1,779.7		1,976.5

Fees from midstream services:
Revenue recognized from contracts with customers:
NGL transportation and services		45.8			37.5			122.0			115.8
Gathering and processing														115.9		194.5
NGL transportation, fractionation and services														40.6		36.2
Storage, terminaling and export		84.6			79.6			254.7			233.1			99.7		79.6
Gathering and processing		171.6			196.5			543.7			522.3
Other		6.3			18.7			22.0			33.7			13.0		12.6
Total fees from midstream services		308.3			332.3			942.4			904.9			269.2		322.9

Total revenues	$	1,902.5		$	2,986.4		$	6,197.2		$	7,886.3		$	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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	208.6		$	255.3		$	630.9		$	718.4		$	255.7		$	238.3
Logistics and Marketing operating margin		228.9			173.5			565.0			441.7
Logistics and Transportation operating margin														294.0			152.1
Other operating margin		(63.3	)		(20.8	)		(15.2	)		(42.2	)		116.3			(7.2	)
Depreciation and amortization expense		(244.3	)		(206.3	)		(718.9	)		(607.1	)		(239.1	)		(237.4	)
General and administrative expense		(65.6	)		(59.3	)		(212.3	)		(165.0	)		(57.0	)		(77.7	)
Impairment of long-lived assets														(2,442.8	)		—
Interest expense, net		(84.2	)		(75.7	)		(229.2	)		(113.3	)		(93.8	)		(75.4	)
Gain (loss) from sale of equity-method investment		65.8			—			65.8			—
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		—			(16.6	)		(8.8	)		(12.1	)		—			(9.7	)
Other, net		(8.4	)		(58.8	)		(7.1	)		(10.6	)		(0.5	)		(0.2	)
Income (loss) before income taxes	$	37.5		$	(8.7	)	$	70.2		$	209.8		$	(2,107.9	)	$	(19.0	)

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, ~~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/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, 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~~pipeline (“Grand Prix”), ~~which~~as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix 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 pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the 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 ~~response to increasing production and to meet the infrastructure needs of producers,~~August 2019, we ~~have completed~~announced that we began construction of ~~or have begun constructing three~~a new 250 MMcf/d cryogenic natural gas processing ~~plants~~plant in the Midland Basin. The first plant, the Hopson Plant, began operations in the second quarter of 2019. The second plant, the Pembrook Plant, began operations in the third quarter of 2019. In August 2019, we announced commencement of a third plant,Basin, the Gateway Plant, which is expected to begin operations in the ~~fourth~~third quarter of 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. TIn addition to~~he approximately 220 miles of 12- to 24-inch~~ high-pressure rich gas gathering pipelines ~~that~~and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we ~~constructed across the Delaware Basin are operational. We have recently~~ completed construction of ~~or are currently constructing two new~~a second 250 MMcf/d cryogenic natural gas processing ~~plants in the Delaware Basin. The first~~ plant, the ~~Falcon~~Peregrine Plant, ~~began~~ ~~operations~~ late in the ~~third~~first quarter ~~of 2019. The second plant,~~ ~~the Peregrine Plant, is expected~~and expect it to ~~begin operations~~be operational in the second quarter of 2020. ~~Total growth capital expenditures related to the plants and high-pressure gas pipeline system are expected to be approximately $600 million.~~

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.

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

In the third quarter of 2019, we began full service into Mont Belvieu on Grand Prix, our new common carrier NGL pipeline. Grand Prix transports NGLs from the Permian Basin, North Texas, and Southern Oklahoma to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. The pipeline is comprised of three primary segments:

Grand Prix NGL pipeline system. The Central Oklahoma Extension will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes ~~flowing~~to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be completed in the first quarter of 2021. Transportation volumes on the ~~pipeline from the Permian Basin~~Central Oklahoma Extension accrue solely to ~~Mont Belvieu~~ Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit. Total growth capital spending on Grand Prix, including the extensions into Oklahoma, is estimated to be approximately $2.0 billion, with our portion of growth capital spending estimated to be approximately $1.4 billion.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 the second quarter of 2019~~. The total cost of the fractionation train and related infrastructure was 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, were funded and are 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~~. Train 7 began operations late in the first quarter of 2020. Train 8 is expected to begin operations ~~by the end of the first quarter of 2020 and~~at the end of the third quarter of 2020~~respectively. The total cost of these~~. In January 2019, Williams committed to Targa significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams was also granted an option to purchase a 20% equity interest in the fractionation ~~trains and related infrastructure is expected to be approximately $825 million. In connection with the Central Oklahoma Extension,~~train, which was originally wholly owned by Targa. Williams exercised its initial option ~~to acquire a 20% equity interest in Train 7~~ and executed a joint venture agreement with 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 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, we entered into definitive joint venture agreements to form Gulf Coast Express Pipeline LLC (“GCX”) with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) for the purpose of developing the Gulf Coast Express Pipeline (“GCX Pipeline”), a natural gas pipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipeline provides 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 34% interest, and Altus Midstream Company owns the remaining 16% interest in GCX. KMTP serves as the 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 GCX Pipeline. 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 was placed in service late in the third quarter of 2019.

In April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC (“Targa Badlands”), 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 and hold majority governance rights. Future growth capital~~ ~~of Targa Badlands~~ is expected to be funded on a pro rata ownership basis. Targa Badlands pays 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.~~

We continue to evaluate and execute asset sales to reduce leverage and focus on our core operations. During the third quarter of 2019, we closed on the sale of an equity-method investment for $70.3 million. In November 2019, we executed agreements to sell our crude gathering and storage business in the Permian Delaware for approximately ~~$135~~$134 million. ~~Subject to customary regulatory approvals and closing conditions, the~~The sale ~~is expected to close~~closed early in the ~~fourth~~first quarter of ~~2019.~~2020.

~~We have also engaged Jefferies LLC to evaluate~~During the ~~potential divestiture~~three months ended March 31, 2020, we repurchased a portion of our ~~crude gathering business in~~outstanding senior notes on the Permian Midland, which includes crude gathering and storage assets. The potential divestiture is predicated on third party valuations adequately capturing our forward growth expectations for the assets, and no assurance can be made that a sale will be consummated.

~~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 $1,486.6 million. The net proceeds from the issuance 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 ~~repayment~~the write-off of ~~borrowings under~~$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. 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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions)												(In millions)
Reconciliation of Net Income (Loss) to Operating Margin and Gross Margin
Net income (loss)	$	37.5		$	(8.7	)	$	70.2		$	209.8		$	(2,107.9	)	$	(19.0	)
Depreciation and amortization expense		244.3			206.3			718.9			607.1			239.1			237.4
General and administrative expense		65.6			59.3			212.3			165.0			57.0			77.7
Impairment of long-lived assets														2,442.8			—
Interest (income) expense, net		84.2			75.7			229.2			113.3			93.8			75.4
Equity (earnings) loss														(20.6	)		(2.8	)
(Gain) loss on sale or disposition of assets		0.5			61.1			3.6			14.3			0.6			3.2
Write-down of assets		17.9			—			17.9			—
(Gain) loss from sale of equity-method investment		(65.8	)		—			(65.8	)		—
(Gain) loss from financing activities		—			—			1.4			1.3			(39.3	)		1.4
Change in contingent considerations		—			16.6			8.8			12.1
Other, net		(10.0	)		(2.3	)		(15.7	)		(5.0	)		0.5			9.9
Operating margin		374.2			408.0			1,180.8			1,117.9			666.0			383.2
Operating expenses		200.2			194.9			600.7			538.7			194.6			190.2
Gross margin	$	574.4		$	602.9		$	1,781.5		$	1,656.6		$	860.6		$	573.4

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			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	$	(39.1	)	$	(18.4	)	$	(74.1	)	$	177.8		$	(2,022.6	)	$	(30.4	)
Interest (income) expense, net ~~(1)~~		84.2			75.7			229.2			113.3			93.8			75.4
Depreciation and amortization expense		244.3			206.3			718.9			607.1			239.1			237.4
Impairment of long-lived assets														2,442.8			—
(Gain) loss on sale or disposition of assets		0.5			61.1			3.6			14.3			0.6			3.2
Write-down of assets		17.9			—			17.9			—
(Gain) loss from sale of equity-method investment		(65.8	)		—			(65.8	)		—
(Gain) loss from financing activities (2)		—			—			1.4			1.3
(Gain) loss from financing activities (1)														(39.3	)		1.4
Equity (earnings) loss		(10.0	)		(3.0	)		(15.9	)		(6.4	)		(20.6	)		(2.8	)
Distributions from unconsolidated affiliates and preferred partner interests, net		14.0			7.5			33.4			21.4			25.7			6.8
Change in contingent considerations		—			16.6			8.8			12.1
Risk management activities		100.7			(0.8	)		100.8			8.3			(115.5	)		7.2
Noncontrolling interests adjustments (3)		(8.9	)		(7.7	)		(25.6	)		(19.7	)
TRP Adjusted EBITDA (4)	$	337.8		$	337.3		$	932.6		$	929.5
Noncontrolling interests adjustments (2)														(189.4	)		(7.1	)
TRP Adjusted EBITDA													$	414.6		$	291.1

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

	Three Months Ended September 30,												Nine Months Ended September 30,												Three Months Ended March 31,
	2019			2018			2019 vs. 2018						2019			2018			2019 vs. 2018						2020			2019			2020 vs. 2019
	(In millions)																								(In millions)
Revenues:
Sales of commodities	$	1,594.2		$	2,654.1		$	(1,059.9	)		(40	%)	$	5,254.8		$	6,981.4		$	(1,726.6	)		(25	%)	$	1,779.7		$	1,976.5		$	(196.8	)		(10	%)
Fees from midstream services		308.3			332.3			(24.0	)		(7	%)		942.4			904.9			37.5			4	%		269.2			322.9			(53.7	)		(17	%)
Total revenues		1,902.5			2,986.4			(1,083.9	)		(36	%)		6,197.2			7,886.3			(1,689.1	)		(21	%)		2,048.9			2,299.4			(250.5	)		(11	%)
Product purchases		1,328.1			2,383.5			(1,055.4	)		(44	%)		4,415.7			6,229.7			(1,814.0	)		(29	%)		1,188.3			1,726.0			(537.7	)		(31	%)
Gross margin (1)		574.4			602.9			(28.5	)		(5	%)		1,781.5			1,656.6			124.9			8	%		860.6			573.4			287.2			50	%
Operating expenses		200.2			194.9			5.3			3	%		600.7			538.7			62.0			12	%		194.6			190.2			4.4			2	%
Operating margin (1)		374.2			408.0			(33.8	)		(8	%)		1,180.8			1,117.9			62.9			6	%		666.0			383.2			282.8			74	%
Depreciation and amortization expense		244.3			206.3			38.0			18	%		718.9			607.1			111.8			18	%		239.1			237.4			1.7			1	%
General and administrative expense		65.6			59.3			6.3			11	%		212.3			165.0			47.3			29	%		57.0			77.7			(20.7	)		(27	%)
Impairment of long-lived assets																										2,442.8			—			2,442.8			—
Other operating (income) expense		18.4			61.8			(43.4	)		(70	%)		21.7			15.7			6.0			38	%		1.1			3.4			(2.3	)		(68	%)
Income (loss) from operations		45.9			80.6			(34.7	)		(43	%)		227.9			330.1			(102.2	)		(31	%)		(2,074.0	)		64.7			(2,138.7	)	NM
Interest expense, net		(84.2	)		(75.7	)		(8.5	)		(11	%)		(229.2	)		(113.3	)		(115.9	)		(102	%)		(93.8	)		(75.4	)		(18.4	)		24	%
Equity earnings (loss)		10.0			3.0			7.0			233	%		15.9			6.4			9.5			148	%		20.6			2.8			17.8		NM
Gain (loss) from financing activities		—			—			—			—			(1.4	)		(1.3	)		(0.1	)		(8	%)		39.3			(1.4	)		40.7		NM
Gain (loss) from sale of equity-method investment		65.8			—			65.8			—			65.8			—			65.8			—
Change in contingent considerations		—			(16.6	)		16.6			100	%		(8.8	)		(12.1	)		3.3			27	%		—			(9.7	)		9.7			100	%
Net income (loss)		37.5			(8.7	)		46.2		NM				70.2			209.8			(139.6	)		(67	%)		(2,107.9	)		(19.0	)		(2,088.9	)	NM
Less: Net income (loss) attributable to noncontrolling interests		76.6			9.7			66.9		NM				144.3			32.0			112.3		NM				(85.3	)		11.4			(96.7	)	NM
Net income (loss) attributable to Targa Resources Partners LP	$	(39.1	)	$	(18.4	)	$	(20.7	)		113	%	$	(74.1	)	$	177.8		$	(251.9	)		(142	%)	$	(2,022.6	)	$	(30.4	)	$	(1,992.2	)	NM
Financial data:
Adjusted EBITDA (1)	$	337.8		$	337.3		$	0.5			—		$	932.6		$	929.5		$	3.1			—		$	414.6		$	291.1		$	123.5			42	%
Growth capital expenditures (2)		511.3			984.4			(473.1	)		(48	%)		2,203.4			2,230.0			(26.6	)		(1	%)		277.0			187.0			90.0			48	%
Maintenance capital expenditures (3)		31.0			33.3			(2.3	)		(7	%)		101.5			80.4			21.1			26	%		26.8			870.0			(843.2	)		(97	%)

Three Months Ended ~~September 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2018~~March 31, 2019

The decrease in commodity sales reflects lower NGL, natural gas, and condensate prices ($~~1,352.5 million), the unfavorable impact of mark-to-market hedges ($102.0~~863.3 million) and lower ~~petroleum products and condensate~~crude marketing volumes ($~~62.2~~37.9 million), partially offset by higher NGL, ~~crude marketing and~~ natural gas, petroleum products, and condensate volumes ($~~373.3~~547.9 million), and the favorable impact of ~~equity volume~~ hedges ($~~59.5 million) and higher crude marketing prices ($20.1~~148.0 million).

The decrease in fees from midstream services is ~~largely~~primarily due to ~~lower gas gathering fees attributable to our non-cash take in-kind equity~~new transportation arrangements for Badlands volumes ~~partially offset by an overall increase~~during the three months ended March 31, 2020, which resulted in ~~gas gathered volumes. Subsequent to our January 2018 adoption of ASC 606, Revenue~~a change from ~~Contracts with Customers, non-cash take in-kind volumes, which have exposure to commodity prices, received from a customer are presented~~net presentation as ~~a component of~~ fees from midstream services ~~with a corresponding offset~~ to gross presentation as sales of commodities and product purchases, ~~and have no impact to our operating margin or gross margin.~~

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

Lower 2019 operating margin and gross margin reflect decreased segment results for Gathering and Processing, offset by increased segment results for Logistics and Marketing. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis. Operating margin and gross margin also include the effect of hedges as discussed in “—Other.”

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including additional processing plants and associated infrastructure in the Permian Basin and Grand Prix.

General and administrative expense increased primarily due to higher compensation and benefits costs as a result of increased staffing levels, partially offset by lower professional services and lower contract labor.

During the third quarter of 2019, we wrote down certain assets to their recoverable amounts. In the prior year, a loss on sale was recognized associated with our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD.

~~Interest expense, net, increased due to higher average borrowings, partially offset by higher capitalized interest related to our major growth investments.~~

~~The increase in equity earnings is primarily due to higher earnings from GCX.~~

~~During the third quarter of 2019, we closed on the sale of an equity-method investment for $70.3 million that resulted in the recognition of a gain of $65.8 million.~~

During 2019, the Permian Acquisition contingent consideration earn-out period ended and resulted in a final payment in May. During 2018, we recorded an expense resulting primarily from an increase in fair value of the contingent consideration liability. The fair value change was primarily attributable to a shorter discount period.

~~Net income attributable to noncontrolling interests was higher in 2019 due to earnings allocated to noncontrolling interest holders in Targa Badlands, Grand Prix and Train 6.~~

~~Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018~~

The decrease in commodity sales reflects lower commodity prices ($2,640.8 million) and lower petroleum products volumes due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018 ($85.3 million), partially offset by higher NGL, crude marketing and natural gas volumes ($936.4 million) and the favorable impact of hedges ($65.8 million). Higher exports and crude gathering fees resulted in increased fees from midstream services.

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

Higher ~~2019~~ operating margin and gross margin in 2020 reflect increased segment results for Gathering and Processing and Logistics and ~~Marketing, offset by decreased segment results for Gathering and Processing.~~Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis. ~~Operating margin and gross margin also include the effect of hedges as discussed in “—Other.”~~

General and administrative expense ~~increased~~decreased primarily due to ~~higher~~lower compensation and benefits costs ~~as a~~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 ~~of increased staffing levels and higher system costs.~~in future impairments.

Interest expense, net, increased due to higher average borrowings ~~partially offset by higher~~and lower capitalized interest ~~related to our major~~resulting from lower growth investments. ~~During 2018, we recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemable interests, primarily attributable to~~ ~~the February 2018 amendments to such arrangements.~~

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

During ~~2019,~~the three months ended March 31, 2020, we ~~closed~~repurchased a portion of our outstanding senior notes on the ~~sale~~open market, paying $122.1 million plus accrued interest to repurchase $162.7 million of ~~an equity-method investment for $70.3~~the notes, resulting in a $39.3 million ~~that resulted in the recognition of a~~net gain ~~of $65.8 million.~~from financing activities.

Net income attributable to noncontrolling interests was ~~higher~~lower in ~~2019~~2020 primarily due to ~~earnings~~impairment losses allocated to noncontrolling interest holders, partially offset by income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), Targa GCX Pipeline LLC and the Grand Prix ~~and Train 6.~~Joint Venture.

																				Three Months Ended March 31,
	Three Months Ended September 30,									Nine Months Ended September 30,										2020		2019		2020 vs. 2019
	2019		2018		2019 vs. 2018					2019		2018			2019 vs. 2018					(In millions, except operating statistics and price amounts)
Gross margin	$	328.8	$	373.7	$	(44.9	)	(12	%)	$	1,006.1	$	1,046.3	$		(40.2	)	(4	%)	$	370.3	$	361.2	$	9.1		3	%
Operating expenses		120.2		118.4		1.8		2	%		375.2		327.9			47.3		14	%		114.6		122.9		(8.3	)	(7	%)
Operating margin	$	208.6	$	255.3	$	(46.7	)	(18	%)	$	630.9	$	718.4	$		(87.5	)	(12	%)	$	255.7	$	238.3	$	17.4		7	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,546.7		1,161.7		385.0		33	%		1,438.7		1,100.8			337.9		31	%		1,655.0		1,322.6		332.4		25	%
Permian Delaware		629.4		470.5		158.9		34	%		552.2		432.5			119.7		28	%		727.0		480.4		246.6		51	%
Total Permian		2,176.1		1,632.2		543.9					1,990.9		1,533.3			457.6					2,382.0		1,803.0		579.0

SouthTX (5)		328.6		364.1		(35.5	)	(10	%)		335.3		397.8			(62.5	)	(16	%)		286.3		363.9		(77.6	)	(21	%)
North Texas		228.2		247.6		(19.4	)	(8	%)		227.6		243.0			(15.4	)	(6	%)		223.4		230.5		(7.1	)	(3	%)
SouthOK (6)		590.8		568.2		22.6		4	%		606.1		549.4			56.7		10	%		564.0		620.0		(56.0	)	(9	%)
WestOK		329.2		353.9		(24.7	)	(7	%)		335.2		350.8			(15.6	)	(4	%)		291.6		338.1		(46.5	)	(14	%)
Total Central		1,476.8		1,533.8		(57.0	)				1,504.2		1,541.0			(36.8	)				1,365.3		1,552.5		(187.2	)

Badlands (7), (8)		120.8		90.5		30.3		33	%		103.4		83.3			20.1		24	%
Badlands (7),(8)																					159.7		96.9		62.8		65	%
Total Field		3,773.7		3,256.5		517.2					3,598.5		3,157.6			440.9					3,907.0		3,452.4		454.6

Coastal		721.0		783.3		(62.3	)	(8	%)		765.1		724.5			40.6		6	%		784.7		769.9		14.8		2	%

Total		4,494.7		4,039.8		454.9		11	%		4,363.6		3,882.1			481.5		12	%		4,691.7		4,222.3		469.4		11	%
NGL production, MBbl/d (3)
Permian Midland (4)		216.5		152.2		64.3		42	%		199.8		148.0			51.8		35	%		244.9		184.3		60.6		33	%
Permian Delaware		82.3		58.9		23.4		40	%		71.4		51.6			19.8		38	%		96.3		60.5		35.8		59	%
Total Permian		298.8		211.1		87.7					271.2		199.6			71.6					341.2		244.8		96.4

SouthTX (5)		41.5		49.0		(7.5	)	(15	%)		44.0		52.5			(8.5	)	(16	%)		28.2		48.8		(20.6	)	(42	%)
North Texas		27.3		29.6		(2.3	)	(8	%)		26.9		28.1			(1.2	)	(4	%)		26.3		26.8		(0.5	)	(2	%)
SouthOK (6)		69.5		61.2		8.3		14	%		65.4		53.8			11.6		22	%		66.8		58.3		8.5		15	%
WestOK		19.2		20.7		(1.5	)	(7	%)		22.4		19.9			2.5		13	%		23.2		24.1		(0.9	)	(4	%)
Total Central		157.5		160.5		(3.0	)				158.7		154.3			4.4					144.5		158.0		(13.5	)

Badlands (8)		14.0		10.5		3.5		33	%		12.2		10.5			1.7		16	%		18.1		11.4		6.7		59	%
Total Field		470.3		382.1		88.2					442.1		364.4			77.7					503.8		414.2		89.6

Coastal		45.4		47.3		(1.9	)	(4	%)		47.0		42.8			4.2		10	%		48.8		48.4		0.4		1	%

Total		515.7		429.4		86.3		20	%		489.1		407.2			81.9		20	%		552.6		462.6		90.0		19	%
Crude oil gathered, Badlands, MBbl/d		164.3		161.7		2.6		2	%		167.0		139.9			27.1		19	%		177.1		169.5		7.6		4	%
Crude oil gathered, Permian, MBbl/d		95.2		75.1		20.1		27	%		86.1		63.8			22.3		35	%
Natural gas sales, BBtu/d (3)		2,056.6		1,817.6		239.0		13	%		2,011.2		1,821.1			190.1		10	%
NGL sales, MBbl/d		398.0		329.6		68.4		21	%		382.4		311.3			71.1		23	%
Crude oil gathered, Permian, MBbl/d (9)																					50.9		76.5		(25.6	)	(33	%)
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		11.0		12.6		(1.6	)	(13	%)		12.2		12.8			(0.6	)	(5	%)		18.6		12.5		6.1		49	%
Average realized prices (9):
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu		1.02		1.93		(0.91	)	(47	%)		1.19		2.03			(0.84	)	(41	%)		0.93		1.94		(1.01	)	(53	%)
NGL, $/gal		0.27		0.75		(0.48	)	(64	%)		0.35		0.67			(0.32	)	(48	%)		0.22		0.45		(0.22	)	(50	%)
Condensate, $/Bbl		50.94		58.31		(7.37	)	(13	%)		49.79		58.49			(8.70	)	(15	%)		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 ~~September 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2018~~March 31, 2019

The ~~decrease~~increase in gross margin was primarily due to ~~lower commodity prices,~~higher volumes in the Permian and Badlands, partially offset by ~~higher Permian~~lower Central volumes and ~~Badlands volumes. The impact of~~ lower realized commodity ~~prices in 2019 excludes the third quarter realized gain from our 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 inlet ~~volumes and increased NGL recoveries.~~volumes. In the Permian, ~~natural gas gathered~~inlet volumes and NGL production increased due to incremental processing capacity available with the commencement of operations at the Johnson Plant in the fourth quarter of 2018, the Hopson Plant in the second quarter of 2019 and the Pembrook Plant in the third quarter of 2019, while total crude oil gathered volumes increased due to production from new ~~wells. In~~wells and the ~~Badlands, natural gas gathered volumes and NGL production increased due to incremental processing capacity available with the commencement~~addition of ~~operations at the Little Missouri 4 Plant in the third quarter of 2019, while total crude oil gathered volumes increased due to production from new wells.~~

~~Operating expenses were relatively flat with increased operating expenses in the Permian, due to gas plant and system expansions, partially offset by reductions in other regions.~~

~~Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018~~

The decrease in gross margin was primarily due to lower commodity prices, partially offset by higher Permian and Badlands volumes. The impact of lower commodity prices in 2019 excludes the realized gain from our hedging activities presented in Other. NGL production, NGL sales and natural gas sales increased primarily due to higher inlet volumes and increased NGL recoveries. In the Permian, natural gas gathered volumes and NGL production increased due to incremental processing capacity available with the commencement of operations at the Johnson Plant in the fourth quarter of 2018, the Hopson, ~~Plant~~Pembrook and Falcon plants in ~~the second quarter of 2019 and the Pembrook Plant in the third quarter of~~ 2019. In the Badlands, natural gas gathered volumes and NGL 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 ~~increased~~ in ~~both~~ the Permian ~~region and~~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 Badlands due to production from new wells.

~~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 and the Badlands. Operating expenses in other areas were relatively flat.~~Permian.

		Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended March 31,
		2019		2018		2019 vs. 2018					2019		2018		2019 vs. 2018						2020		2019		2020 vs. 2019
	(In millions)																			(In millions, except operating statistics and price amounts)
Gross margin		$	310.4	$	249.4	$	61.0		24	%	$	792.4	$	653.1	$	139.3		21	%		$	375.0	$	219.5	$	155.5		71	%
Operating expenses			81.5		75.9		5.6		7	%		227.4		211.4		16.0		8	%			81.0		67.4		13.6		20	%
Operating margin		$	228.9	$	173.5	$	55.4		32	%	$	565.0	$	441.7	$	123.3		28	%		$	294.0	$	152.1	$	141.9		93	%
Operating statistics MBbl/d (1):
Fractionation volumes (2)			508.8		454.5		54.3		12	%		492.8		419.0		73.8		18	%			625.3		456.6		168.7		37	%
Export volumes (3)			239.2		208.2		31.0		15	%		228.1		200.2		27.9		14	%			268.9		213.1		55.8		26	%
Pipeline throughput (4)			131.8		-		131.8		-			44.4		-		44.4		-				261.7		-		261.7		-
NGL sales			672.1		555.7		116.4		21	%		620.9		526.7		94.2		18	%			748.2		584.3		163.9		28	%
Average realized prices:
NGL realized price, $/gal		$	0.43	$	0.88	$	(0.45	)	(51	%)	$	0.50	$	0.80	$	(0.30	)	(38	%)		$	0.40	$	0.60	$	(0.20	)	(33	%)

Three Months Ended ~~September 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2018~~March 31, 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 ~~and services~~ margin, ~~higher marketing margin, and~~ higher LPG export margin, ~~partially offset by lower terminaling~~ and ~~storage throughput.~~higher marketing margin. NGL transportation ~~fractionation~~ and ~~services~~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 volumes as a result of the commencement of operations of Train 6 in the second quarter of ~~2019. Fractionation~~2019 and ~~services margin was unfavorably impacted by fewer short-term high fee fractionation contracts~~Train 7 in the ~~third~~first quarter of ~~2019~~2020. LPG export margin increased due to higher volumes in the first quarter of 2020 compared to the same period last ~~year, and by a planned maintenance turnaround of our Cedar Bayou fractionator.~~year. Marketing margin increased due to optimization of gas and liquids arrangements. ~~LPG export margin increased due to higher volumes. Terminaling and storage throughput decreased due to the sale of certain petroleum logistics terminals in the fourth quarter of 2018.~~

Operating expenses increased due to higher ~~maintenance, higher fuel and power costs that are largely passed through to customers, and higher compensation and benefits~~taxes primarily attributable to ~~Grand Prix and Train 6 operations, partially offset by~~ the ~~sale of certain petroleum logistics terminals in the fourth quarter of 2018.~~

~~Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018~~

Logistics and Marketing gross margin increased due to higher NGL transportation, fractionation and services margin, higher LPG export margin, and higher marketing margin, partially offset by lower terminaling and storage throughput. NGL transportation, fractionation and services 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 volumes as a result of the commencement of~~ operations of Train 6 in the second quarter of 2019. Fractionation and services margin was unfavorably impacted by fewer short-term high fee fractionation contracts in the third quarter of 2019 compared to the same period last year, and by a planned maintenance turnaround of our Cedar Bayou fractionator. LPG export margin increased due to higher volumes. Marketing margin increased due to optimization of gas and liquids arrangements. Terminaling and storage throughput decreased due to the sale of certain petroleum logistics terminals in the fourth quarter of 2018.

~~Operating expenses increased due to higher fuel and power costs that are largely passed through to customers,~~Grand Prix, higher maintenance, and higher compensation and benefits ~~and higher taxes primarily~~ attributable to ~~Grand Prix~~Train 6 and Train ~~6 operations, partially offset by the sale of certain petroleum logistics terminals in the fourth quarter of 2018.~~7 operations.

	Three Months Ended September 30,									Nine Months Ended September 30,								Three Months Ended March 31,
	2019			2018			2019 vs. 2018			2019			2018			2019 vs. 2018		2020		2019			2020 vs. 2019
	(In millions)																	(In millions)
Gross margin	$	(63.3	)	$	(20.8	)	$	(42.5	)	$	(15.2	)	$	(42.2	)	$	27.0	$	116.3	$	(7.2	)	$	123.5
Operating margin	$	(63.3	)	$	(20.8	)	$	(42.5	)	$	(15.2	)	$	(42.2	)	$	27.0	$	116.3	$	(7.2	)	$	123.5

Other contains the results of commodity derivative ~~activities~~activity mark-to-market gains/losses related to ~~Gathering and Processing hedges of equity volumes~~derivative contracts that ~~are included in operating margin. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating~~were not designated as cash ~~flow.~~flow hedges. 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.~~

We have also entered into swaps and basis swaps that are not designated or do not qualify for hedge accounting treatment. The mark-to-market gains/losses related to these derivative instruments represent unrealized, non-cash changes in the fair value of the instruments. For the three and nine months ended September 30, 2019, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices and will be more than offset by locked-in gains to be realized in future periods from the underlying transportation arrangements.

~~The following table provides a breakdown of the change in Other operating margin:~~Qualitative Disclosures About Market Risk.”

As of ~~September 30, 2019,~~March 31, 2020, we had ~~$294.9~~$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.

		November 1, 2019				May 1, 2020
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	287.0		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		349.0		Total availability under the Securitization Facility		181.1
			2,836.0				2,669.2

Less:	Outstanding borrowings under the TRP Revolver		(880.0	)	Outstanding borrowings under the TRP Revolver		(610.0	)
	Outstanding borrowings under the Securitization Facility		(349.0	)	Outstanding borrowings under the Securitization Facility		(181.1	)
	Outstanding letters of credit under the TRP Revolver		(73.8	)	Outstanding letters of credit under the TRP Revolver		(71.6	)
	Total liquidity	$	1,533.2		Total liquidity	$	1,806.5

Other potential capital resources associated with our existing arrangements include:

On April 22, 2020, we amended the 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 facility termination date to April 21, 2021.

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 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 ~~September 30, 2019~~March 31, 2020 increased ~~$1,167.8~~$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~~derivative contracts and ~~the May 2019 contingent consideration payment associated with the Permian Acquisition, with funding provided by the issuance of long-term senior notes.~~a lower outstanding balance on our 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 ~~September 30, 2019,~~March 31, 2020, total contributions from Stonepeak to the DevCo JVs were ~~$880.1~~$906.5 million. As of ~~September 30, 2019,~~March 31, 2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were $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 ~~September 30, 2019,~~March 31, 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 ~~$6,844.7~~$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 ~~September 30, 2019,~~March 31, 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 $1,486.6 million. The net proceeds from the issuance were used to redeem in full our 4⅛% Senior Notes due 2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment of borrowings under our credit facilities.

~~In April~~ 2019, we closed on the sale of a 45% interest in Targa Badlands ~~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 and hold majority governance rights. Future growth Growth capital of Targa Badlands after the sale is ~~expected to be~~ funded on a pro rata ownership basis. Targa Badlands pays ~~an MQD~~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 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 ~~September 30, 2019,~~March 31, 2020, the contributions from ~~Blackstone~~GSO were ~~$63.0~~$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 ~~September 30, 2019,~~March 31, 2020, we were in compliance with the covenants contained in our various debt agreements.

Nine Months Ended September 30,
2019		2018		2019 vs. 2018
Three Months Ended March 31,							Three Months Ended March 31,
2020							2020	2019		2020 vs. 2019
(In millions)	(In millions)						(In millions)
$	897.4	$	943.5	$	(46.1	)	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 ~~operating activities decreased~~operations increased in ~~2019~~2020 compared to ~~2018~~2019 primarily due to higher operating margin and an increase in cash settlements from hedging activity, partially offset by an increase in interest payments as a result of higher average borrowings.

Nine Months Ended September 30,
2019			2018			2019 vs. 2018
Three Months Ended March 31,									Three Months Ended March 31,
2020									2020		2019			2020 vs. 2019
(In millions)	(In millions)								(In millions)
$	(2,619.7	)	$	(2,192.8	)	$	(426.9	)	(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 ~~$400.5~~$601.6 million, ~~primarily 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 ~~$20.0~~$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.

	Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2020			2019
Source of Financing Activities, net	(In millions)						(In millions)
Sale of ownership interests in subsidiaries	$	1,619.7		$	—
Distributions							$	(241.9	)	$	(241.3	)
Contributions from (distributions to) noncontrolling interests								(94.5	)		196.8
Debt, including financing costs		823.7			904.2			132.9			732.7
Contributions from noncontrolling interests		518.7			611.6
Contributions from TRC and General Partner		200.0			540.0
Distributions		(921.5	)		(692.1	)
Payment of contingent consideration		(317.1	)		—
Other		(109.6	)		(51.6	)		-			(18.6	)
Net cash provided by (used in) financing activities	$	1,813.9		$	1,312.1		$	(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 ~~the sale of ownership interests in Targa Badlands and Train 7,~~a net increase of debt outstanding, ~~and~~ contributions from noncontrolling ~~interests. The result was~~interests, partially offset by payments of ~~distributions, as well as the final contingent consideration payment associated with the Permian Acquisition.~~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.~~projects.

In 2018, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding and contributions from noncontrolling interests and TRC, partially offset by payments of distributions to TRC. The issuance of 5⅞% Senior Notes due 2026, partially offset by repayments of outstanding borrowings under TRP Revolver contributed to the net increase of debt outstanding. 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 ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:

Distributions on our Preferred Units are declared and paid monthly. As of ~~September 30, 2019,~~March 31, 2020, we have 5,000,000 Preferred Units outstanding. For the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, $2.8 ~~million and $8.4~~ million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for ~~September,~~March, which were paid subsequently on ~~October~~April 15, ~~2019.~~2020.

In ~~October 2019,~~April 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 ~~November~~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. 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 ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

							Three Months Ended March 31,
	Nine Months Ended September 30,						2020			2019
	2019			2018			(In millions)
Capital expenditures:	(In millions)
Growth (1)		2,203.4			2,230.0		$	277.0		$	870.0
Maintenance (2)		101.5			80.4			26.8			35.6
Gross capital expenditures		2,304.9			2,310.4			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		(21.7	)		(8.9	)		(1.7	)		(1.1	)
Change in capital project payables and accruals		150.6			(283.9	)		39.6			38.4
Cash outlays for capital projects		2,433.8			2,033.6		$	341.7		$	942.9

We currently estimate that in ~~2019~~2020 we will invest approximately ~~$2,400~~$700 million to $800 million in growth capital expenditures, net of noncontrolling interests, ~~(exclusive of outlays for business acquisitions),~~ 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~~2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $130 million.

Total growth capital expenditures ~~were flat~~reduced for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 as compared to the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to lower spending on growth investments as Grand Prix, ~~as it began full service in the third quarter, partially offset by spending related to construction of~~ 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 ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 as compared to the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to ~~our increased asset base and additional infrastructure.~~timing of maintenance projects.

As of ~~September 30, 2019,~~March 31, 2020, there were ~~$55.2~~$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.

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 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 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 ~~September 30, 2019,~~March 31, 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 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 ~~September 30, 2019~~March 31, 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	$	(72.9	)	$	(27.1	)	$	(118.5	)	$	(11.6	)	$	37.1	$	(59.9	)
NGLs		124.5			166.2			83.1			145.9			172.8		118.8
Crude oil		18.9			36.3			1.4			75.6			88.1		63.0
Total	$	70.5		$	175.4		$	(34.0	)	$	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 ~~decreased~~increased (decreased) by ~~$61.8~~$161.4 million and ($~~24.9 million~~11.8 million) during the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018, and $7.7 million and $73.6 million during the nine months ended September 30, 2019 and 2018,~~ 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 ~~$70.5~~$209.9 million at ~~September 30, 2019.~~March 31, 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 ~~September 30, 2019,~~March 31, 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 ~~September 30, 2019,~~March 31, 2020, we had ~~$1,076.0~~$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 ~~$10.8~~$6.3 million based on our ~~September 30, 2019~~March 31, 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 ~~$129.6~~$65.4 million as of ~~September 30, 2019.~~March 31, 2020. The range of losses attributable to our individual counterparties as of ~~September 30, 2019~~March 31, 2020 would be between ~~$0.1~~$2.5 million and ~~$36.7~~$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 ~~September 30, 2019, our operating income would decrease by $7.4 million~~March 31, 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 ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 11% and 12% of our consolidated revenues. During the three and nine months ended September 30, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 17% and 16% 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 ~~September 30, 2019,~~March 31, 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 in addition to the ~~updates~~risk factors discussed below. All of these risks and uncertainties, including ~~the updates~~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 ~~tax treatment~~prices of ~~publicly traded partnerships~~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 ~~investment~~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 ~~our Preferred Units could be subject~~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 ~~potential legislative, judicial or administrative changes~~both demand and ~~differing interpretations, possibly applied on~~supply disruptions was a ~~retroactive basis.~~significant contributing factor to the non-cash impairment charges totaling $2,442.8 million for the three months ended March 31, 2020.

The ~~present U.S. federal income tax treatment~~widespread outbreak of ~~publicly traded partnerships, including us,~~the COVID-19 pandemic or ~~an investment in us,~~any other public health crisis that impacts the global demand for commodities may ~~be modified by administrative, legislative~~ have material adverse effects on our business, financial position, results of operations and/or ~~judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes~~cash flows.

We face risks related to the ~~existing U.S. federal income tax laws~~outbreak of illnesses, pandemics and other public health crises that ~~would~~are outside of our control and could significantly disrupt our operations and adversely affect ~~publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships.~~our financial condition. For example, the ~~“Clean Energy~~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 America Act”, which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the U.S. Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal Section 7704(d)(1)(E)oil and gas, and created significant volatility and disruption of financial and commodity markets. The full extent of the Internal Revenue Code upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretationimpact of the ~~qualifying income rules in a manner that could impact~~COVID-19 pandemic on our operational and financial performance, including our ability to ~~qualify as a partnership for U.S. federal income tax purposes~~execute our business strategies and initiatives in the ~~future.~~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.

~~Any modification~~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 ~~U.S. federal income tax laws may~~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 ~~applied retroactively~~reasonably estimated at this time.

Refer to Note 4 – Property, Plant and ~~could make it more difficult or impossible~~Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in us. You are urged to consult with your own tax advisor with respect to the status of legislative or administrative developments and proposals and their potential effect on your investment in our Preferred Units.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

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of ~~September~~ ~~30, 2019~~ March 31, 2020 and December 31, ~~2018~~2019		4

Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September~~ ~~30,~~March 31, 2020 and 2019 ~~and~~ ~~2018~~		5

Consolidated Statements of Comprehensive Income (Loss) for the three ~~and nine~~ months ended ~~September~~ ~~30,~~March 31, 2020 and 2019 ~~and~~ ~~2018~~		6

Consolidated Statements of Changes in Owners' Equity for the three ~~and nine~~ months ended ~~September 30,~~ March 31, 2020 and 2019 ~~and 2018~~		7

Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September~~ ~~30,~~March 31, 2020 and 2019 ~~and 2018~~		98

Notes to Consolidated Financial Statements		109

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		3024

Item 3. Quantitative and Qualitative Disclosures About Market Risk		4840

Item 4. Controls and Procedures		5042

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		5143

Item 1A. Risk Factors		5143

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		5144

Item 3. Defaults Upon Senior Securities		5144

Item 4. Mine Safety Disclosures		5144

Item 5. Other Information		5144

Item 6. Exhibits		5245

SIGNATURES

Signatures		5447


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

	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

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

Balance at December 31, 2018	$	1,983.2
Amortization		(128.8	)
Balance at September 30, 2019	$	1,854.4

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


(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.

	Balance Sheet Location	September 30, 2019
Right-of-use assets
Operating leases, gross	Other long-term assets	$	31.5
Finance leases, gross	Property, plant and equipment		46.9

Lease liabilities
Current:
Operating leases	Accounts payable and accrued liabilities	$	6.9
Finance leases	Current debt obligations		12.0
Non-current:
Operating leases	Other long-term liabilities	$	19.6
Finance leases	Long-term debt		26.9

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Lease cost
Operating lease cost	$	2.2	$	6.0
Short-term lease cost		6.7		22.4
Variable lease cost		0.8		3.6
Finance lease cost
Amortization of right-of-use assets		3.4		9.7
Interest expense		0.4		1.2
Total lease cost	$	13.5	$	42.9

	Operating Leases			Finance Leases
Future Minimum Lease Payments Beginning After September 30,
2019	$	7.8		$	13.3
2020		6.9			11.4
2021		6.1			10.3
2022		4.6			6.1
2023		2.6			0.6
Thereafter		0.7			—
Total undiscounted cash flows		28.7			41.7
Less imputed interest		(2.2	)		(2.8	)
Total lease liabilities	$	26.5		$	38.9

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

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2019	November 13, 2019	$		242.1	$		239.3
June 30, 2019	August 13, 2019			242.4			239.6
March 31, 2019	April 5, 2019			437.8			435.0
December 31, 2018	February 13, 2019			241.3			238.5

		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
	New Level 3 derivative instruments		(0.4	)		—
	Transfers out of Level 3 (1)		(6.5	)		—
	Unrealized gain/(loss) included in OCI		1.5			—
Balance, September 30, 2019		$	1.1		$	(2.4	)

		2019				2020				2021 and after
Fixed consideration to be recognized as of September 30, 2019		$	130.8			$	486.3			$	3,474.4

		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 September 30, 2018
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	296.7	$	2,378.2	$	(20.8	)	$	—		$	2,654.1
Fees from midstream services		199.3		133.0		—			—			332.3
		496.0		2,511.2		(20.8	)		—			2,986.4
Intersegment revenues
Sales of commodities		1,069.7		15.5		—			(1,085.2	)		—
Fees from midstream services		1.5		8.5		—			(10.0	)		—
		1,071.2		24.0		—			(1,095.2	)		—
Revenues	$	1,567.2	$	2,535.2	$	(20.8	)	$	(1,095.2	)	$	2,986.4
Operating margin	$	255.3	$	173.5	$	(20.8	)	$	—		$	408.0
Other financial information:
Total assets (1)	$	11,331.5	$	5,019.0	$	64.2		$	111.8		$	16,526.5
Goodwill	$	256.6	$	—	$	—		$	—		$	256.6
Capital expenditures	$	453.0	$	560.7	$	—		$	4.0		$	1,017.7

	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 filed December 12, 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~~10.1*	Supplemental Indenture dated ~~July 19, 2019~~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 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.2~~10.2*	Supplemental Indenture dated ~~July 19, 2019~~February 20, 2020 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.3~~10.3*	Supplemental Indenture dated ~~July 19, 2019~~February 20, 2020 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.4~~10.4*	Supplemental Indenture dated ~~July 19, 2019~~February 20, 2020 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.5~~10.5*	Supplemental Indenture dated ~~July 19, 2019~~February 20, 2020 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association (incorporated by reference to Exhibit 10.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.6~~10.6*	Supplemental Indenture dated ~~July 19, 2019~~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 (incorporated by reference to Exhibit 10.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-33303)).~~Association.

~~10.7~~10.7*	Supplemental Indenture dated ~~July 19, 2019~~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~~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. 2020 Annual Incentive Compensation Plan (incorporated by reference to Exhibit ~~10.8~~10.1 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2019~~January 23, 2020 (File No. 001-33303)).

Number		Description

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.

~~Number~~		~~Description~~

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.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document

104*	The cover page from this Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2019,~~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: ~~November~~May 7, ~~2019~~2020	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)

Nine Months Ended September 30, 2019

Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows for operating leases

Operating cash flows for finance leases

Financing cash flows for finance leases