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 ~~October 29, 2021,~~May 3, 2022, there were ~~228,971,730~~227,987,890 shares of the registrant’s common stock, $0.001 par value, outstanding.

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

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

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

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2021~~March 31, 2022 (“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, 2021			December 31, 2020				March 31, 2022			December 31, 2021
		(Unaudited)							(Unaudited)
		(In millions)							(In millions)
ASSETS	ASSETS							ASSETS
Current assets:
Cash and cash equivalents		$	228.6		$	242.8			$	135.9		$	158.5
Trade receivables, net of allowances of $3.6 million and $0.1 million at September 30, 2021 and December 31, 2020			1,291.0			862.8
Trade receivables, net of allowances of $0.1 million and $0.1 million at March 31, 2022 and December 31, 2021										1,567.2			1,331.9
Inventories			316.8			181.5				97.5			153.4
Assets from risk management activities			82.7			85.5				22.0			43.1
Other current assets			74.2			87.7				77.9			82.9
Total current assets			1,993.3			1,460.3				1,900.5			1,769.8
Property, plant and equipment, net			11,922.4			12,173.6				11,653.0			11,667.7
Intangible assets, net			1,284.2			1,382.4				1,066.8			1,094.8
Long-term assets from risk management activities			13.4			49.3				7.3			7.7
Investments in unconsolidated affiliates			674.6			714.0				579.8			586.5
Other long-term assets			84.8			96.1				88.0			81.7
Total assets		$	15,972.7		$	15,875.7			$	15,295.4		$	15,208.2

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY	LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY							LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable		$	1,652.3		$	833.8			$	1,803.5		$	1,402.3
Accrued liabilities			240.2			186.4				202.5			272.2
Distributions payable			71.0			115.4				46.3			64.5
Interest payable			79.9			132.6				74.5			138.5
Liabilities from risk management activities			472.3			142.6				499.8			258.2
Current debt obligations			352.6			368.6				283.8			162.8
Total current liabilities			2,868.3			1,779.4				2,910.4			2,298.5
Long-term debt			6,434.1			7,387.1				6,964.9			6,434.4
Long-term liabilities from risk management activities			151.2			43.4				267.2			109.3
Deferred income taxes, net			78.7			152.1				88.0			136.0
Other long-term liabilities			290.8			309.1				297.9			301.6
Contingencies (see Note 13)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, 919,300 shares issued and outstanding), net of discount (see Note 7)			749.7			301.4
Contingencies (see Note 15)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, 919,300 shares issued and outstanding as of March 31, 2022 and December 31, 2021), net of discount (see Note 9)										749.7			749.7
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 450,000,000 shares authorized)			0.2			0.2
Common stock ($0.001 par value, 450,000,000 shares authorized as of March 31, 2022 and December 31, 2021)										0.2			0.2
Issued Outstanding
September 30, 2021 236,086,963 228,962,972
December 31, 2020 234,792,888 228,061,853
March 31, 2022 237,199,124 228,180,573
December 31, 2021 236,105,293 228,221,122
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, 0 shares issued and outstanding)			0			0				0			0
Additional paid-in capital			4,299.7			4,839.9				4,125.8			4,268.9
Retained earnings (deficit)			(1,508.7	)		(1,893.5	)			(1,734.3	)		(1,822.3	)
Accumulated other comprehensive income (loss)			(442.1	)		(141.8	)			(418.4	)		(230.9	)
Treasury stock, at cost (7,123,991 shares as of September 30, 2021 and 6,731,035 shares as of December 31, 2020)			(164.0	)		(150.9	)
Treasury stock, at cost (9,018,551 shares as of March 31, 2022 and 7,884,171 shares as of December 31, 2021)										(276.3	)		(204.1	)
Total Targa Resources Corp. stockholders' equity			2,185.1			2,653.9				1,697.0			2,011.8
Noncontrolling interests			3,214.8			3,249.3				2,320.3			3,166.9
Total owners' equity			5,399.9			5,903.2				4,017.3			5,178.7
Total liabilities, Series A Preferred Stock and owners' equity		$	15,972.7		$	15,875.7			$	15,295.4		$	15,208.2

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2021			2020			2022			2021
	(Unaudited)												(Unaudited)
	(In millions, except per share amounts)												(In millions, except per share amounts)
Revenues:
Sales of commodities	$	4,118.1		$	1,840.8		$	10,577.3		$	4,900.8		$	4,566.2		$	3,367.7
Fees from midstream services		341.6			274.3			930.9			786.7			392.9			265.0
Total revenues		4,459.7			2,115.1			11,508.2			5,687.5			4,959.1			3,632.7
Costs and expenses:
Product purchases and fuel		3,614.7			1,322.9			9,159.8			3,405.1			4,204.1			2,836.3
Operating expenses		189.4			162.2			545.3			506.8			183.5			171.1
Depreciation and amortization expense		222.8			203.7			650.9			647.3			209.1			216.2
General and administrative expense		67.3			58.6			192.4			180.6			67.1			61.4
Impairment of long-lived assets		—			—			—			2,442.8
Other operating (income) expense		(1.0	)		72.2			3.4			73.8			(0.5	)		3.6
Income (loss) from operations		366.5			295.5			956.4			(1,568.9	)		295.8			344.1
Other income (expense):
Interest expense, net		(91.0	)		(97.7	)		(284.2	)		(292.4	)		(93.6	)		(98.4	)
Equity earnings (loss)		14.3			18.6			38.9			54.1			5.6			11.8
Gain (loss) from financing activities		—			(13.7	)		(16.6	)		47.4			(15.8	)		(14.7	)
Other, net		0.2			1.4			0.3			2.2			(0.5	)		0.1
Income (loss) before income taxes		290.0			204.1			694.8			(1,757.6	)		191.5			242.9
Income tax (expense) benefit		(2.0	)		(31.9	)		(23.5	)		286.6			(22.9	)		(15.0	)
Net income (loss)		288.0			172.2			671.3			(1,471.0	)		168.6			227.9
Less: Net income (loss) attributable to noncontrolling interests		105.8			102.9			286.5			116.5			80.6			81.5
Net income (loss) attributable to Targa Resources Corp.		182.2			69.3			384.8			(1,587.5	)		88.0			146.4
Premium on repurchase of noncontrolling interests, net of tax														53.1			—
Dividends on Series A Preferred Stock		21.8			22.9			65.5			68.8			21.8			21.8
Deemed dividends on Series A Preferred Stock		—			9.5			—			27.7
Net income (loss) attributable to common shareholders	$	160.4		$	36.9		$	319.3		$	(1,684.0	)	$	13.1		$	124.6

Net income (loss) per common share - basic	$	0.70		$	0.16		$	1.40		$	(7.22	)	$	0.06		$	0.54
Net income (loss) per common share - diluted	$	0.66		$	0.16		$	1.38		$	(7.22	)	$	0.06		$	0.53
Weighted average shares outstanding - basic		228.8			233.4			228.6			233.2			228.5			228.5
Weighted average shares outstanding - diluted		276.4			233.8			231.6			233.2			232.4			274.7

	Three Months Ended September 30,																	Three Months Ended March 31,
	2021									2020								2022									2021
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax		After Tax			Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax			After Tax
	(Unaudited)																	(Unaudited)
	(In millions)																	(In millions)
Net income (loss)							$	288.0							$	172.2								$	168.6								$	227.9
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	(294.7	)	$	71.2			(223.5	)	$	(128.7	)	$	31.7		(97.0	)	$	(387.1	)	$	86.6			(300.5	)	$	(171.5	)	$	40.2			(131.3	)
Settlements reclassified to revenues		100.4			(24.6	)		75.8			(19.2	)		3.8		(15.4	)		145.7			(32.7	)		113.0			149.7			(35.0	)		114.7
Other comprehensive income (loss)		(194.3	)		46.6			(147.7	)		(147.9	)		35.5		(112.4	)		(241.4	)		53.9			(187.5	)		(21.8	)		5.2			(16.6	)
Comprehensive income (loss)								140.3								59.8									(18.9	)								211.3
Less: Comprehensive income (loss) attributable to noncontrolling interests								105.8								102.9						��			80.6									81.5
Comprehensive income (loss) attributable to Targa Resources Corp.							$	34.5							$	(43.1	)							$	(99.5	)							$	129.8

	Nine Months Ended September 30,
	2021									2020
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax		After Tax
	(Unaudited)
	(In millions)
Net income (loss)							$	671.3							$	(1,471.0	)
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	(698.9	)	$	167.1			(531.8	)	$	(102.6	)	$	23.5		(79.1	)
Settlements reclassified to revenues		303.8			(72.3	)		231.5			(139.4	)		35.2		(104.2	)
Other comprehensive income (loss)		(395.1	)		94.8			(300.3	)		(242.0	)		58.7		(183.3	)
Comprehensive income (loss)								371.0								(1,654.3	)
Less: Comprehensive income (loss) attributable to noncontrolling interests								286.5								116.5
Comprehensive income (loss) attributable to Targa Resources Corp.							$	84.5							$	(1,770.8	)

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated																								Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A							Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred		Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock		Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)																											(Unaudited)
	(In millions, except shares in thousands)																											(In millions, except shares in thousands)
Balance, June 30, 2021		228,655		$	0.2	$	4,330.8		$	(1,690.9	)	$	(294.4	)		7,016	$	(159.5	)	$	3,210.3		$	5,396.5		$	749.7
Balance, December 31, 2021																													228,221		$	0.2	$	4,268.9		$	(1,822.3	)	$	(230.9	)		7,884	$	(204.1	)	$	3,166.9		$	5,178.7		$	749.7
Compensation on equity grants		—			—		14.7			—			—			—		—			—			14.7			—		—			—		13.5			—			—			—		—			—			13.5			—
Distribution equivalent rights		—			—		(1.1	)		—			—			—		—			—			(1.1	)		—		—			—		(1.7	)		—			—			—		—			—			(1.7	)		—
Shares issued under compensation program		416			—		—			—			—			—		—			—			—			—		1,095			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(108	)		—		—			—			—			108		(4.5	)		—			(4.5	)		—
Shares tendered for tax withholding obligations																													(397	)		—		—			—			—			397		(22.5	)		—			(22.5	)		—
Repurchases of common stock																													(738	)		—		—			—			—			738		(49.7	)		—			(49.7	)		—
Series A Preferred Stock dividends
Dividends - $23.75 per share		—			—		—			(21.8	)		—			—		—			—			(21.8	)		—		—			—		—			(21.8	)		—			—		—			—			(21.8	)		—
Dividends in excess of retained earnings		—			—		(21.8	)		21.8			—			—		—			—			—			—		—			—		(21.8	)		21.8			—			—		—			—			—			—
Common stock dividends
Dividends - $0.10 per share		—			—		—			(22.9	)		—			—		—			—			(22.9	)		—
Dividends - $0.35 per share																													—			—		—			(80.0	)		—			—		—			—			(80.0	)		—
Dividends in excess of retained earnings		—			—		(22.9	)		22.9			—			—		—			—			—			—		—			—		(80.0	)		80.0			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(110.4	)		(110.4	)		—		—			—		—			—			—			—		—			(72.2	)		(72.2	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			9.1			9.1			—		—			—		—			—			—			—		—			2.9			2.9			—
Repurchase of noncontrolling interests, net of tax																													—			—		(53.1	)		—			—			—		—			(857.9	)		(911.0	)		—
Other comprehensive income (loss)		—			—		—			—			(147.7	)		—		—			—			(147.7	)		—		—			—		—			—			(187.5	)		—		—			—			(187.5	)		—
Net income (loss)		—			—		—			182.2			—			—		—			105.8			288.0			—		—			—		—			88.0			—			—		—			80.6			168.6			—
Balance, September 30, 2021		228,963		$	0.2	$	4,299.7		$	(1,508.7	)	$	(442.1	)		7,124	$	(164.0	)	$	3,214.8		$	5,399.9		$	749.7
Balance, March 31, 2022																													228,181		$	0.2	$	4,125.8		$	(1,734.3	)	$	(418.4	)		9,019	$	(276.3	)	$	2,320.3		$	4,017.3		$	749.7

~~CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK~~

Retained

Accumulated

Additional

Earnings

Other

Treasury

Total

Series A

Common Stock

Paid in

(Accumulated

Comprehensive

Shares

Noncontrolling

Owner's

Preferred

Shares

Amount

Capital

Deficit)

Income (Loss)

Shares

Amount

Interests

Equity

Stock

(Unaudited)

(In millions, except shares in thousands)

Balance, June 30, 2020

233,177

$
0.2

$
4,949.1

$
(1,996.4
)

$
21.6

1,116

$
(56.9
)

$
3,351.5

$
6,269.1

$
297.0

Compensation on equity grants

—

—

16.4

—

—

—

—

—

16.4

—

Distribution equivalent rights

—

—

1.9

—

—

—

—

—

1.9

—

Shares issued under compensation program

453

—

—

—

—

—

—

—

—

—

Shares and units tendered for tax withholding obligations

(112
)

—

—

—

—

112

(2.1
)

—

(2.1
)

—

Series A Preferred Stock dividends

Dividends - $23.75 per share

—

—

—

(22.9
)

—

—

—

—

(22.9
)

—

Dividends in excess of retained earnings

—

—

(22.9
)

22.9

—

—

—

—

—

—

Deemed dividends - accretion of beneficial conversion feature

—

—

(9.5
)

—

—

—

—

—

(9.5
)

9.5

Common stock dividends

Dividends - $0.10 per share

—

—

—

(23.3
)

—

—

—

—

(23.3
)

—

Dividends in excess of retained earnings

—

—

(23.3
)

23.3

—

—

—

—

—

—

Distributions to noncontrolling interests

—

—

—

—

—

—

—

(113.1
)

(113.1
)

—

Contributions from noncontrolling interests

—

—

—

—

—

—

—

7.7

7.7

—

Non-cash allocation to noncontrolling interests

—

—

—

—

—

—

—

27.5

27.5

—

Other comprehensive income (loss)

—

—

—

—

(112.4
)

—

—

—

(112.4
)

—

Net income (loss)

—

—

—

69.3

—

—

—

102.9

172.2

—

Balance, September 30, 2020

233,518

$
0.2

$
4,911.7

$
(1,927.1
)

$
(90.8
)

1,228

$
(59.0
)

$
3,376.5

$
6,211.5

$
306.5

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

Retained

Accumulated

Additional

Earnings

Other

Treasury

Total

Series A

Common Stock

Paid in

(Accumulated

Comprehensive

Shares

Noncontrolling

Owner's

Preferred

Shares

Amount

Capital

Deficit)

Income (Loss)

Shares

Amount

Interests

Equity

Stock

(Unaudited)

(In millions, except shares in thousands)

Balance, December 31, 2020

228,062

$
0.2

$
4,839.9

$
(1,893.5
)

$
(141.8
)

6,731

$
(150.9
)

$
3,249.3

$
5,903.2

$
301.4

Impact of accounting standard adoption (see Note 3)

—

—

(448.3
)

—

—

—

—

—

(448.3
)

448.3

Compensation on equity grants

—

—

44.6

—

—

—

—

—

44.6

—

Distribution equivalent rights

—

—

(2.4
)

—

—

—

—

—

(2.4
)

—

Shares issued under compensation program

1,294

—

—

—

—

—

—

—

—

—

Shares and units tendered for tax withholding obligations

(393
)

—

—

—

—

393

(13.1
)

—

(13.1
)

—

Series A Preferred Stock dividends

Dividends - $71.25 per share

—

—

—

(65.5
)

—

—

—

—

(65.5
)

—

Dividends in excess of retained earnings

—

—

(65.5
)

65.5

—

—

—

—

—

—

Common stock dividends

Dividends - $0.30 per share

—

—

—

(68.6
)

—

—

—

—

(68.6
)

—

Dividends in excess of retained earnings

—

—

(68.6
)

68.6

—

—

—

—

—

—

Distributions to noncontrolling interests

—

—

—

—

—

—

—

(334.2
)

(334.2
)

—

Contributions from noncontrolling interests

—

—

—

—

—

—

—

13.2

13.2

—

Other comprehensive income (loss)

—

—

—

—

(300.3
)

—

—

—

(300.3
)

—

Net income (loss)

—

—

—

384.8

—

—

—

286.5

671.3

—

Balance, September 30, 2021

228,963

$
0.2

$
4,299.7

$
(1,508.7
)

$
(442.1
)

7,124

$
(164.0
)

$
3,214.8

$
5,399.9

$
749.7

~~CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK~~

									Retained			Accumulated																									Retained			Accumulated
						Additional			Earnings			Other			Treasury									Total			Series A							Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owner's			Preferred		Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity			Stock		Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)																												(Unaudited)
	(In millions, except shares in thousands)																												(In millions, except shares in thousands)
Balance, December 31, 2019		232,844		$	0.2	$	5,221.2		$	(339.6	)	$	92.5			1,010		$	(53.5	)	$	3,522.1		$	8,442.9		$	278.8
Balance, December 31, 2020																														228,062		$	0.2	$	4,839.9		$	(1,893.5	)	$	(141.8	)		6,731	$	(150.9	)	$	3,249.3		$	5,903.2		$	301.4
Impact of accounting standard adoption																														—			—		(448.3	)		—			—			—		—			—			(448.3	)		448.3
Compensation on equity grants		—			—		49.5			—			—			—			—			—			49.5			—		—			—		15.0			—			—			—		—			—			15.0			—
Distribution equivalent rights		—			—		(3.5	)		—			—			—			—			—			(3.5	)		—		—			—		(0.4	)		—			—			—		—			—			(0.4	)		—
Shares issued under compensation program		892			—		—			—			—			—			—			—			—			—		878			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(218	)		—		—			—			—			218			(5.5	)		—			(5.5	)		—
Shares tendered for tax withholding obligations																														(285	)		—		—			—			—			285		(8.6	)		—			(8.6	)		—
Series A Preferred Stock dividends
Dividends - $71.25 per share		—			—		—			(68.8	)		—			—			—			—			(68.8	)		—
Dividends - $23.75 per share																														—			—		—			(21.8	)		—			—		—			—			(21.8	)		—
Dividends in excess of retained earnings		—			—		(68.8	)		68.8			—			—			—			—			—			—		—			—		(21.8	)		21.8			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(27.7	)		—			—			—	��		—			—			(27.7	)		27.7
Common stock dividends
Dividends - $1.11 per share		—			—		—			(259.0	)		—			—			—			—			(259.0	)		—
Dividends - $0.10 per share																														—			—		—			(22.9	)		—			—		—			—			(22.9	)		—
Dividends in excess of retained earnings		—			—		(259.0	)		259.0			—			—			—			—			—			—		—			—		(22.9	)		22.9			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—			—			(322.9	)		(322.9	)		—		—			—		—			—			—			—		—			(107.1	)		(107.1	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—			—			33.3			33.3			—		—			—		—			—			—			—		—			2.0			2.0			—
Non-cash allocation to noncontrolling interests		—			—		—			—			—			—			—			27.5			27.5			—
Other comprehensive income (loss)		—			—		—			—			(183.3	)		—			—			—			(183.3	)		—		—			—		—			—			(16.6	)		—		—			—			(16.6	)		—
Net income (loss)		—			—		—			(1,587.5	)		—			—			—			116.5			(1,471.0	)		—		—			—		—			146.4			—			—		—			81.5			227.9			—
Balance, September 30, 2020		233,518		$	0.2	$	4,911.7		$	(1,927.1	)	$	(90.8	)		1,228		$	(59.0	)	$	3,376.5		$	6,211.5		$	306.5
Balance, March 31, 2021																														228,655		$	0.2	$	4,361.5		$	(1,747.1	)	$	(158.4	)		7,016	$	(159.5	)	$	3,225.7		$	5,522.4		$	749.7

	Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2022			2021
	(Unaudited)						(Unaudited)
	(In millions)						(In millions)
Cash flows from operating activities
Net income (loss)	$	671.3		$	(1,471.0	)	$	168.6		$	227.9
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		7.8			8.5			2.4			2.7
Compensation on equity grants		44.6			49.5			13.5			15.0
Depreciation and amortization expense		650.9			647.3			209.1			216.2
Impairment of long-lived assets		—			2,442.8
(Gain) loss on sale or disposition of assets								(1.0	)		—
Write-downs of assets								0.5			3.5
Accretion of asset retirement obligations		3.0			2.6			1.1			0.9
Increase (decrease) in redemption value of mandatorily redeemable preferred interests								(0.7	)		—
Deferred income tax expense (benefit)		21.5			(269.8	)		21.1			14.5
Equity (earnings) loss of unconsolidated affiliates		(38.9	)		(54.1	)		(5.6	)		(11.8	)
Distributions of earnings received from unconsolidated affiliates		64.5			65.5			6.0			24.3
Risk management activities		55.6			(214.2	)		178.2			(1.5	)
(Gain) loss on sale or disposition of business and assets		(1.7	)		58.0
Write-downs of assets		5.0			13.5
(Gain) loss from financing activities		16.6			(47.4	)		15.8			14.7
Changes in operating assets and liabilities:
Receivables and other assets		(359.8	)		168.7			(216.2	)		(41.9	)
Inventories		(128.0	)		(115.8	)		55.9			139.9
Accounts payable, accrued liabilities and other liabilities		839.1			(158.0	)		363.5			121.2
Interest payable		(52.7	)		(30.4	)		(64.0	)		(45.8	)
Net cash provided by operating activities		1,798.8			1,095.7			748.2			679.8
Cash flows from investing activities
Outlays for property, plant and equipment		(321.6	)		(803.1	)		(204.4	)		(96.2	)
Proceeds from sale of business and assets		7.9			135.9
Proceeds from sale of assets								1.0			—
Investments in unconsolidated affiliates		(0.6	)		(2.2	)		(0.4	)		—
Return of capital from unconsolidated affiliates		14.5			10.7			6.8			5.9
Other, net		0.2			4.7			—			0.3
Net cash used in investing activities		(299.6	)		(654.0	)		(197.0	)		(90.0	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		620.0			1,460.0			1,805.0			65.0
Repayments of credit facilities		(1,455.0	)		(1,360.0	)		(810.0	)		(825.0	)
Proceeds from borrowings under accounts receivable securitization facility		570.0			476.4			250.0			350.0
Repayments of accounts receivable securitization facility		(580.0	)		(596.4	)		(130.0	)		(430.0	)
Proceeds from issuance of senior notes		1,000.0			1,000.0			—			1,000.0
Redemption of senior notes		(1,132.0	)		(831.0	)		(480.7	)		(548.1	)
Principal payments of finance leases		(9.4	)		(9.3	)		(3.2	)		(3.1	)
Costs incurred in connection with financing arrangements		(9.6	)		(9.6	)		(10.9	)		(9.0	)
Repurchase of shares and units under compensation plans		(13.1	)		(5.5	)
Repurchase of shares								(72.2	)		(8.6	)
Contributions from noncontrolling interests		13.2			33.3			2.9			2.0
Distributions to noncontrolling interests		(377.3	)		(310.6	)		(90.4	)		(129.3	)
Distributions to Partnership unitholders		—			(8.4	)
Repurchase of noncontrolling interests								(926.3	)		—
Dividends paid to common and Series A Preferred shareholders		(140.2	)		(336.7	)		(108.0	)		(48.0	)
Net cash provided by (used in) financing activities		(1,513.4	)		(497.8	)		(573.8	)		(584.1	)
Net change in cash and cash equivalents		(14.2	)		(56.1	)		(22.6	)		5.7
Cash and cash equivalents, beginning of period		242.8			331.1			158.5			242.8
Cash and cash equivalents, end of period	$	228.6		$	275.0		$	135.9		$	248.5

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 Corp. ~~(“TRC”)~~(NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. ~~Our common stock~~Targa is ~~listed on~~a leading provider of midstream services and is one of the ~~New York Stock Exchange under the symbol “TRGP.”~~largest independent infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.

In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the ~~Company”~~Company,” “Targa” or ~~“Targa”~~“TRGP” are intended to mean our consolidated business and operations. ~~TRC~~TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership” ~~or “TRP.”~~

~~We conduct our operations through our direct and indirect subsidiaries in Targa Resources Partners LP (the “Partnership” or “TRP”)~~. Targa consolidates ~~TRP~~the Partnership and its subsidiaries under ~~GAAP. Our~~accounting principles generally accepted in the United States of America (“GAAP”). Targa’s consolidated financial statements ~~do not differ materially~~include differences from the consolidated financial statements of ~~TRP.~~the Partnership. The most noteworthy differences are:

See Note 1719 – Segment Information for certain financial information regarding our business segments.

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 intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation. Operating results for the three ~~and nine~~ months ended ~~September 30, 2021~~March 31, 2022 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2021.~~

Certain amounts in prior periods have been reclassified to conform to the current year presentation. Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel within our Consolidated Statements of Operations to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business. For the three and nine months ended September 30, 2021, we reclassified $14.3 million and $49.2 million in fuel and power costs, respectively. For the three and nine months ended September 30, 2020, we reclassified $19.7 million and $58.3 million in fuel and power costs, respectively.

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~~There were no significant updates or revisions to our accounting policies during the ~~nine~~three months ended ~~September 30, 2021.~~

~~In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06,~~ Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. ~~The amendments in~~this update simplify the accounting for convertible debt instruments and convertible preferred stock by reducing the number of accounting models and embedded conversion features that can be recognized separately from the primary contract. These amendments also enhance transparency and improve disclosures for convertible instruments and earnings per share guidance. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2021, with early adoption permitted. This update permits the use of either the modified retrospective or full retrospective method of adoption.

On a modified retrospective basis, we adopted the amendments early, effective January 1, 2021. The primary effect of the adoption on the Company was attributable to the elimination of the beneficial conversion accounting model, which results in the presentation of the Series A Preferred as a single unit of account, without bifurcation of the beneficial conversion feature and corresponding discount. Therefore, upon adoption, the carrying value of the Series A Preferred was reflected at $749.7 million, which is the allocated amount based on the initial relative fair value allocation of net proceeds of $787.1 million, less the carrying value of the portion repurchased in December 2020. The adoption did not have an impact on retained earnings (deficit), but rather, the adoption impact flowed through additional paid-in capital where the beneficial conversion feature was previously included. In addition, the adoption also eliminates the corresponding discount attributable to the beneficial conversion feature and therefore, accretion of the discount as a deemed dividend is no longer required. The other aspects of the ASU did not have a material effect on our consolidated financial statements.March 31, 2022.

In February 2018, we formed 3 development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix NGL Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”) and an approximately 110 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). For a four-year period beginning on the date that all three projects commenced commercial operations, we had the option to acquire all or part of Stonepeak’s interests in the DevCo JVs (the “DevCo JV Call Right”). The purchase price payable for such partial or full interests was based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs.

In January 2022, we exercised the DevCo JV Call Right and closed on the purchase of all of Stonepeak’s interests in the DevCo JVs for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75% interest in Grand Prix Pipeline LLC, a 100% interest in Train 6 and owned a 25% equity interest in GCX, prior to the GCX Sale (as defined below) in February 2022. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was $53.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

In February 2022, we announced that we executed agreements to sell Targa GCX Pipeline LLC, which held our 25 percent equity interest in GCX, for approximately $857 million (the “GCX Sale”). We expect to receive the full proceeds from the sale in the second quarter of 2022 as the customary call right period has now expired.

In April 2022, we closed on the acquisition of Southcross Energy Operating LLC and its subsidiaries in South Texas for a purchase price of approximately $200 million (the “Southcross Acquisition”). We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the 2 operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and which we will prospectively consolidate. See Note 6 – Investments in Unconsolidated Affiliates.

	September 30, 2021			December 31, 2020			Estimated Useful Lives (In Years)	March 31, 2022			December 31, 2021			Estimated Useful Lives (In Years)
Gathering systems	$	9,279.7		$	9,216.1		5 to 20	$	9,368.0		$	9,318.2		5 to 20
Processing and fractionation facilities		6,365.1			6,276.8		5 to 25		6,423.0			6,388.8		5 to 25
Terminaling and storage facilities		1,313.5			1,555.1		5 to 25		1,325.5			1,313.8		5 to 25
Transportation assets		2,628.4			2,567.7		10 to 50		2,696.6			2,671.0		10 to 50
Other property, plant and equipment		355.3			32.4		3 to 50		334.2			340.9		3 to 50
Land		160.8			160.8		—		160.8			160.8		—
Construction in progress		263.1			324.3		—		392.4			347.0		—
Finance lease right-of-use assets		55.2			51.8				56.8			55.6		5 to 7
Property, plant and equipment		20,421.1			20,185.0				20,757.3			20,596.1
Accumulated depreciation, amortization and impairment		(8,498.7	)		(8,011.4	)			(9,104.3	)		(8,928.4	)
Property, plant and equipment, net	$	11,922.4		$	12,173.6			$	11,653.0		$	11,667.7

Intangible assets		2,643.5			2,643.5		10 to 20		2,497.7			2,642.9		10 to 20
Accumulated amortization and impairment		(1,359.3	)		(1,261.1	)			(1,430.9	)		(1,548.1	)
Intangible assets, net	$	1,284.2		$	1,382.4			$	1,066.8		$	1,094.8

During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, depreciation expense was ~~$190.2~~$181.1 million and ~~$552.7~~$183.4 million, respectively. ~~During the three and nine months ended September 30, 2020, depreciation expense was $168.5 million and $538.5 million, respectively.~~

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, including changes to our estimates that could have an impact on our assessment of asset recoverability.

During the first quarter of 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter of 2020 from certain major oil producing nations increasing production also significantly contributed to the sharp drop in commodity prices. The drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. As a result, we determined that indicators of impairment existed for certain asset groups reported primarily within our Gathering and Processing segment, and recorded non-cash pre-tax NaN impairments of $2,442.8 million (inclusive of impairments of intangible assets) primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations. Our first quarter 2020 impairment assessment forecasted continuing decline in natural gas production across the Mid-Continent and Gulf of Mexico regions. The carrying value adjustments are included in Impairment of long-lived assets ~~in our Consolidated Statements of Operations.~~

~~We determined fair value through~~were recorded for the ~~use of discounted estimated cash flows to measure the impairment loss for each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value.~~

~~The estimated cash flows used to assess recoverability of our long-lived assets~~three months ended March 31, 2022 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 terminal value and 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 determination of terminal values. We utilized a weighted average discount rate of 14.0% when deriving the fair value of the asset groups impaired during the first quarter of 2020. The weighted average discount rate and terminal values reflect management’s best estimate of inputs a market participant would utilize.

While commodity prices remain volatile and uncertainties associated with the impacts of COVID-19 continue, production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed. There were no indicators of impairment identified during the remainder of 2020 or first nine months of 2021.

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.

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, in the first quarter of 2020, we~~ recognized a non-cash pre-tax impairment loss of $208.6 million 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 ~~$130.9~~$112.0 million, ~~$122.7~~$106.8 million, ~~$117.5~~$103.0 million, ~~$113.7~~$99.9 million and ~~$110.6~~$97.6 million for each of the years ~~2021~~2022 through ~~2025,~~2026, respectively.

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.

See Note 4 – Joint Ventures, Divestitures and Acquisitions for further discussion of the T2 Joint Ventures and GCX.

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

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, 2021:~~March 31, 2022:

As of ~~September 30, 2021,~~March 31, 2022, we were in compliance with the covenants contained in our various debt agreements.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of March 31, 2022, $6.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

In February ~~2021,~~2022, we entered into the ~~Partnership issued $1.0 billion~~TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto. The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of ~~4% Senior Notes due 2032, resulting in net proceeds~~the TRGP Revolver), including a swing line sub-facility of ~~approximately $991~~up to $100.0 million. The ~~4% Senior Notes due 2032 have substantially similar terms~~TRGP Revolver matures on February 17, 2027. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver and ~~covenants as our other series of Senior Notes. A portion of~~ the ~~net proceeds~~Partnership Revolver. In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc., and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the ~~issuance were used to fund the concurrent cash tender offer (the “February Tender Offer”) and subsequent redemption payment for the Partnership’s~~ 5⅛~~% Senior Notes due 2025 (the “~~5⅛~~% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver and TRC Revolver.~~liens securing our obligations thereunder. As a result of the ~~February Tender Offer~~termination of the Previous TRGP Revolver and the ~~subsequent redemption of the~~ 5⅛~~% Notes~~,Partnership Revolver, we recorded a loss due to debt extinguishment of ~~$14.9~~$0.8 million.

In March 2022, the Partnership redeemed all of the outstanding 5.375% Notes at a redemption price equal to $1,026.88 for each $1,000 principal amount of 5.375% Notes redeemed, plus accrued and unpaid interest to, but not including, March 30, 2022, or a maximum combined aggregate redemption price (exclusive of accrued and unpaid interest) of $480.7 million. The 5.375% Notes were redeemed with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of ~~$12.5~~$12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

~~Additionally, TPL redeemed all of~~In the ~~outstanding TPL~~ 4¾~~% Senior Notes due 2021 and TPL~~ 5⅞~~% Senior Notes due 2023 (collectively, the “TPL Notes”) on February 22, 2021 with available liquidity under the TRP Revolver. As a result of the redemptions of the TPL Notes,~~future, we ~~recorded a gain due to debt extinguishment of $0.2 million.~~

~~The Partnership redeemed all of the outstanding~~ ~~4¼%~~ Senior Notes due 2023 (the “4¼% Senior Notes”) on May 17, 2021 with available liquidity under the TRP Revolver. As a result of the redemption of the 4¼% Senior Notes, we recorded a loss due to debt extinguishment of $1.9 million.

We or the Partnership may ~~retire~~redeem, purchase or ~~purchase various series~~exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, 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.

In March 2022, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one or more offerings (the “March 2022 Shelf”). The March 2022 Shelf will expire in March 2025. See Note 10 – Common Stock and Related Matters.

The following table summarizes payment obligations as of March 31, 2022, for debt instruments after giving effect to the debt extinguishments detailed above:

	Payments Due By Period										Payments Due By Period
			Less Than						More Than				Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years		Total		1 Year		1-3 Years		3-5 Years		5 Years

Long-term debt obligations (1)	$	6,465.7	$	—	$	—	$	963.2	$	5,502.5	$	6,992.6	$	—	$	—	$	1,958.2	$	5,034.4
Interest on debt obligations (2)		2,547.3		359.4		707.3		674.6		806.0		2,232.6		325.1		650.3		596.0		661.2
	$	9,013.0	$	359.4	$	707.3	$	1,637.8	$	6,308.5	$	9,225.2	$	325.1	$	650.3	$	2,554.2	$	5,695.6

In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Notes and (ii) $750.0 million aggregate principal amount of our 4.950% Notes, resulting in net proceeds of approximately $1.5 billion. Both of the 4.200% Notes and the 4.950% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. Both of the 4.200% Notes and the 4.950% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain First Supplemental Indenture, dated as of April 6, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee.

A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption payment of the Partnership’s 5.875% Notes, with the remainder used for repayment of borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we will record a loss due to debt extinguishment of $33.5 million in the second quarter.

In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.

Other long-term liabilities are 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, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, was ~~$165.8~~$170.6 million and ~~$168.5~~$171.8 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 on the outcome of 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. See Part II—Item 1. Legal Proceedings for further details on the related litigation.

As of ~~September 30, 2021,~~March 31, 2022, we ~~have~~had accrued cumulative preferred dividends of $21.8 million on our Series A Preferred, which ~~will be~~were paid on ~~November 12, 2021.~~May 2, 2022. During the three ~~and nine~~ months ended ~~September 30, 2021,~~March 31, 2022, we paid $21.8 ~~million and $65.5~~ million of dividends to preferred ~~shareholders, respectively.~~shareholders.

In May 2022, we redeemed in ~~the future pursuant to its terms or repurchase~~full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, which will be recorded as deemed dividends in ~~privately negotiated transactions. Such redemptions or repurchases, if any, will depend on prevailing market conditions,~~ our ~~liquidity requirements, contractual restrictions,~~Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have 0 Series A Preferred outstanding and ~~other factors. The amounts involved may be material.~~all rights of the holders of shares of Series A Preferred were terminated.

In March 2022, we filed the March 2022 Shelf. The March 2022 Shelf will expire in March 2025. See Note 7 – Debt Obligations.

In January 2022, we declared an increase to our common dividend to $0.35 per common share or $1.40 per common share annualized effective for the fourth quarter of 2021, which was paid in February 2022.

The following table details the dividends declared and/or paid by us to common shareholders for the ~~nine~~three months ended ~~September 30, 2021:~~March 31, 2022:

We are entitled to receive all Partnership distributions from available cash on the Partnership’s common units each quarter.

The following table details the distributions declared and paid by the Partnership for the ~~nine~~three months ended ~~September 30, 2021:~~March 31, 2022:

All capital contributions to the Partnership continue to be allocated 98% to the limited partner and 2% to the general partner; however, no units will be issued for those contributions. During the ~~nine~~three months ended ~~September 30, 2021,~~March 31, 2022, we made a total of ~~$46.0~~$140.0 million in contributions to the Partnership.

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:

	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
	2021		2020		2021		2020			2022		2021
	(In millions, except per share amounts)									(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.	$	182.2	$	69.3	$	384.8	$	(1,587.5	)	$	88.0	$	146.4
Less: Dividends on Series A Preferred Stock		21.8		22.9		65.5		68.8
Less: Deemed dividends on Series A Preferred Stock		—		9.5		—		27.7
Less: Premium on repurchase of noncontrolling interests, net of tax											53.1		—
Less: Dividends on Series A Preferred (1)											21.8		21.8
Net income (loss) attributable to common shareholders for basic earnings per share	$	160.4	$	36.9	$	319.3	$	(1,684.0	)	$	13.1	$	124.6

Weighted average shares outstanding - basic		228.8		233.4		228.6		233.2			228.5		228.5
Dilutive effect of unvested stock awards		3.3		0.4		3.0		—			3.9		1.9
Dilutive effect of Series A Preferred Stock (1)		44.3		—		—		—
Dilutive effect of Series A Preferred (1)											—		44.3
Weighted average shares outstanding - diluted		276.4		233.8		231.6		233.2			232.4		274.7

Net income (loss) available per common share - basic	$	0.70	$	0.16	$	1.40	$	(7.22	)	$	0.06	$	0.54
Net income (loss) available per common share - diluted	$	0.66	$	0.16	$	1.38	$	(7.22	)	$	0.06	$	0.53

The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2021		2020		2021		2020		2022		2021
Unvested restricted stock awards		—		2.8		0.3		2.5		0.1		—
Series A Preferred Stock (1)		—		46.5		44.3		46.5
Series A Preferred (1)										44.3		—

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have 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 Transportation segment and (iii) natural gas transportation basis risk in our Logistics and 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 primarily 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 and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues as current income.

At ~~September 30, 2021,~~March 31, 2022, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2021		2022		2023		2024		2025		Instrument	Unit	2022		2023		2024		2025		2026		2027
Natural Gas	Swaps	MMBtu/d		188,998		131,613		59,250		16,421		7,479	Swaps	MMBtu/d		157,714		102,943		49,068		7,479		0		0
Natural Gas	Basis Swaps	MMBtu/d		483,779		308,740		250,000		225,000		110,041	Basis Swaps	MMBtu/d		449,755		295,000		280,000		244,267		55,000		10,000
NGL	Swaps	Bbl/d		39,568		29,424		12,557		2,186		0	Swaps	Bbl/d		37,524		23,760		11,209		230		0		0
NGL	Futures	Bbl/d		45,315		740		0		0		0	Futures	Bbl/d		6,429		0		0		0		0		0
Condensate	Swaps	Bbl/d		5,029		3,853		2,155		265		0	Swaps	Bbl/d		5,106		3,687		1,702		37		0		0

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:

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, 2021		Asset		Liability			Collateral		Asset		Liability
March 31, 2022														March 31, 2022	Asset		Liability			Collateral		Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	75.9	$	(338.2	)	$	27.0	$	10.9	$	(246.2	)	Counterparties with offsetting positions or collateral	$	22.0	$	(69.1	)	$	3.7	$	—	$	(43.4	)
	Counterparties without offsetting positions - assets		6.8		—			—		6.8		—		Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		(134.1	)		—		—		(134.1	)	Counterparties without offsetting positions - liabilities		—		(430.7	)		—		—		(430.7	)
			82.7		(472.3	)		27.0		17.7		(380.3	)			22.0		(499.8	)		3.7		—		(474.1	)
Long Term Position
Long-Term Position														Long-Term Position
	Counterparties with offsetting positions or collateral		13.4		(106.9	)		—		3.4		(96.9	)	Counterparties with offsetting positions or collateral		7.3		(203.7	)		15.5		—		(180.9	)
	Counterparties without offsetting positions - assets		—		—			—		—		—		Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		(44.3	)		—		—		(44.3	)	Counterparties without offsetting positions - liabilities		—		(63.5	)		—		—		(63.5	)
			13.4		(151.2	)		—		3.4		(141.2	)			7.3		(267.2	)		15.5		—		(244.4	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		89.3		(445.1	)		27.0		14.3		(343.1	)	Counterparties with offsetting positions or collateral		29.3		(272.8	)		19.2		—		(224.3	)
	Counterparties without offsetting positions - assets		6.8		—			—		6.8		—		Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		(178.4	)		—		—		(178.4	)	Counterparties without offsetting positions - liabilities		—		(494.2	)		—		—		(494.2	)
		$	96.1	$	(623.5	)	$	27.0	$	21.1	$	(521.5	)		$	29.3	$	(767.0	)	$	19.2	$	—	$	(718.5	)

		Gross Presentation							Pro Forma Net Presentation						Gross Presentation							Pro Forma Net Presentation
December 31, 2020		Asset		Liability			Collateral		Asset		Liability
December 31, 2021														December 31, 2021	Asset		Liability			Collateral		Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	81.1	$	(142.0	)	$	29.8	$	15.7	$	(46.8	)	Counterparties with offsetting positions or collateral	$	39.2	$	(241.9	)	$	5.0	$	0.3	$	(198.0	)
	Counterparties without offsetting positions - assets		4.4		—			—		4.4		—		Counterparties without offsetting positions - assets		3.9		—			—		3.9		—
	Counterparties without offsetting positions - liabilities		—		(0.6	)		—		—		(0.6	)	Counterparties without offsetting positions - liabilities		—		(16.3	)		—		—		(16.3	)
			85.5		(142.6	)		29.8		20.1		(47.4	)			43.1		(258.2	)		5.0		4.2		(214.3	)
Long Term Position
Long-Term Position														Long-Term Position
	Counterparties with offsetting positions or collateral		37.8		(42.5	)		—		14.6		(19.3	)	Counterparties with offsetting positions or collateral		7.4		(95.1	)		3.1		—		(84.6	)
	Counterparties without offsetting positions - assets		11.5		—			—		11.5		—		Counterparties without offsetting positions - assets		0.3		—			—		0.3		—
	Counterparties without offsetting positions - liabilities		—		(0.9	)		—		—		(0.9	)	Counterparties without offsetting positions - liabilities		—		(14.2	)		—		—		(14.2	)
			49.3		(43.4	)		—		26.1		(20.2	)			7.7		(109.3	)		3.1		0.3		(98.8	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		118.9		(184.5	)		29.8		30.3		(66.1	)	Counterparties with offsetting positions or collateral		46.6		(337.0	)		8.1		0.3		(282.6	)
	Counterparties without offsetting positions - assets		15.9		—			—		15.9		—		Counterparties without offsetting positions - assets		4.2		—			—		4.2		—
	Counterparties without offsetting positions - liabilities		—		(1.5	)		—		—		(1.5	)	Counterparties without offsetting positions - liabilities		—		(30.5	)		—		—		(30.5	)
		$	134.8	$	(186.0	)	$	29.8	$	46.2	$	(67.6	)		$	50.8	$	(367.5	)	$	8.1	$	4.5	$	(313.1	)

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 the Partnership’s 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. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association (“ISDA”) agreements, which govern the key terms with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Pursuant to the terms of the TRGP Revolver, our derivative positions are no longer secured by the collateral securing the TRGP Revolver. As of March 31, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of approximately ($718) million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of March 31, 2022, we would be required to post approximately $126 million of collateral to certain counterparties per the terms of our ISDAs.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of ($~~527.4)~~737.7) million as of ~~September 30, 2021.~~March 31, 2022. 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	2021			2020			2021			2020			2022			2021
Commodity contracts	$	(294.7	)	$	(128.7	)	$	(698.9	)	$	(102.6	)	$	(387.1	)	$	(171.5	)

	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)	2021			2020		2021			2020		2022			2021
Revenues	$	(100.4	)	$	19.2	$	(303.8	)	$	139.4	$	(145.7	)	$	(149.7	)

Based on valuations as of ~~September 30, 2021,~~March 31, 2022, we expect to reclassify commodity hedge-related deferred losses of ($~~581.7)~~545.4) million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with ($~~433.7)~~423.3) million of losses to be reclassified over the next twelve months.

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

For the three months ended September 30, 2021, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward prices, as compared to our positions. For the nine months ended September 30, 2021,March 31, 2022, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward prices, as compared to our positions.

	Location of Gain (Loss)	Gain (Loss) Recognized in Income on Derivatives									Location of Gain (Loss)	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	2021		2020		2021			2020		Derivatives	2022			2021
Commodity contracts	Revenue	$	16.7	$	90.0	$	(24.8	)	$	197.9	Revenue	$	(177.0	)	$	15.0

See Note 1214 – Fair Value Measurements and Note 1719 – 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 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, 2021,~~March 31, 2022, a net liability position of ($~~527.4)~~737.7) million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of ($~~676.5)~~930.6) million. 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 liability of ($~~378.3)~~544.8) million.

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:

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, 2021										March 31, 2022
	Carrying		Fair Value								Carrying		Fair Value
	Value		Total		Level 1		Level 2		Level 3		Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts(1)	$	96.1	$	96.1	$	0	$	96.1	$	0	$	25.0	$	25.0	$	0	$	25.0	$	0
Liabilities from commodity derivative contracts(1)		623.5		623.5		0		623.4		0.1		762.7		762.7		0		762.7		0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		228.6		228.6		0		0		0		135.9		135.9		0		0		0
TRC Revolver		0		0		0		0		0
TRP Revolver		0		0		0		0		0
TRGP Revolver												995.0		995.0		0		995.0		0
Partnership's Senior unsecured notes		6,465.7		6,909.8		0		6,909.8		0		5,997.6		6,134.7		0		6,134.7		0
Partnership's Securitization Facility		340.0		340.0		0		340.0		0
Securitization Facility												270.0		270.0		0		270.0		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.

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were (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 was immaterial.~~ As of ~~September 30, 2021,~~March 31, 2022, we had 10 derivative ~~contract~~contracts categorized as Level 3.

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

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment. In the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central 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 and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties 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 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. ~~See Part II—Item 1. Legal Proceedings~~

On December 26, 2018, Vitol filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached the Splitter Agreement, which provided for ~~further details~~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 ~~contingencies related~~December 23, 2018, Vitol voluntarily elected to ~~litigation matters.~~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.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company has filed an appeal challenging the award, and the appeal is currently pending in the Fourteenth Court of Appeals in Houston, Texas.

In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings.

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, 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, with remaining contract terms ranging from 1 to 1817 years.

Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.

For disclosures related to disaggregated revenue, see Note 1719 – Segment Information.

The Company records income taxes using an estimated annual effective tax rate and recognizes specific events discretely as they occur. We regularly evaluate the realizable tax benefits of deferred tax assets and record a valuation allowance, if required, based on an estimate of the amount of deferred tax assets that we believe does not meet the more-likely-than-not criteria of being realized.

As of ~~September 30, 2021,~~March 31, 2022, our valuation allowance was ~~$105.4~~$192.8 million, a decrease of ~~$88.8~~$17.8 million from December 31, ~~2020.~~2021. After the change in valuation allowance, we have a net deferred tax liability of ~~$78.7~~$88.0 million.

As we begin achieving sustained profitability, increased consideration will be given to projections of future taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets and may result in a change to our valuation allowance in the next twelve months. We will continue to evaluate the valuation allowance based on current and expected earnings and other factors and adjust accordingly.

In January 2022, the IRS notified us that it will examine Targa’s net operating loss carryback previously claimed under the Coronavirus Aid, Relief and Economic Security Act. We are in the process of responding to information requests from the IRS and do not anticipate material changes in prior year taxable income.

	Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2022			2021
Cash:
Interest paid, net of capitalized interest (1)	$	327.8		$	315.9		$	151.3		$	141.1
Income taxes (received) paid, net		1.2			(44.4	)		(0.2	)		0.8
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		(7.5	)		(194.7	)	$	(41.9	)	$	(12.9	)
Transfers from materials and supplies inventory to property, plant and equipment		2.4			1.9			—			0.1
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests		(43.1	)		3.9		$	(18.2	)	$	(22.2	)

We operate in 2 primary segments: (i) Gathering and Processing, and (ii) Logistics and 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.

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. 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 Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and 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 and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes ~~the~~ Grand Prix, ~~NGL Pipeline (“Grand Prix”),~~ which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our ~~downstream~~Downstream facilities in Mont Belvieu, Texas, as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points.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 unrealized 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, 2021											Three Months Ended March 31, 2022
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	156.2	$	3,948.4	$	13.5	$	—		$	4,118.1	$	134.6	$	4,609.9	$	(178.3	)	$	—		$	4,566.2
Fees from midstream services		205.3		136.3		—		—			341.6		210.4		182.5		—			—			392.9
		361.5		4,084.7		13.5		—			4,459.7		345.0		4,792.4		(178.3	)		—			4,959.1
Intersegment revenues
Sales of commodities		1,786.0		108.3		—		(1,894.3	)		—		2,030.6		124.3		—			(2,154.9	)		—
Fees from midstream services		0.6		11.5		—		(12.1	)		—		0.3		10.8		—			(11.1	)		—
		1,786.6		119.8		—		(1,906.4	)		—		2,030.9		135.1		—			(2,166.0	)		—
Revenues	$	2,148.1	$	4,204.5	$	13.5	$	(1,906.4	)	$	4,459.7	$	2,375.9	$	4,927.5	$	(178.3	)	$	(2,166.0	)	$	4,959.1
Operating margin (1)	$	361.4	$	280.7	$	13.5	$	—		$	655.6	$	397.6	$	352.1	$	(178.3	)
Other financial information:
Total assets (2)	$	8,560.6	$	7,180.5	$	42.3	$	189.3		$	15,972.7	$	7,951.0	$	7,196.0	$	1.6		$	146.8		$	15,295.4
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	98.0	$	16.8	$	—	$	2.7		$	117.5	$	133.0	$	25.2	$	—		$	4.3		$	162.5

	Nine Months Ended September 30, 2021												Three Months Ended March 31, 2021
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	446.2	$	10,186.7	$	(55.6	)	$	—		$	10,577.3	$	142.7	$	3,223.5	$	1.5	$	—		$	3,367.7
Fees from midstream services		496.7		434.2		—			—			930.9		119.4		145.6		—		—			265.0
		942.9		10,620.9		(55.6	)		—			11,508.2		262.1		3,369.1		1.5		—			3,632.7
Intersegment revenues
Sales of commodities		3,940.4		283.5		—			(4,223.9	)		—		969.7		82.5		—		(1,052.2	)		—
Fees from midstream services		2.8		27.0		—			(29.8	)		—		1.6		8.2		—		(9.8	)		—
		3,943.2		310.5		—			(4,253.7	)		—		971.3		90.7		—		(1,062.0	)		—
Revenues	$	4,886.1	$	10,931.4	$	(55.6	)	$	(4,253.7	)	$	11,508.2	$	1,233.4	$	3,459.8	$	1.5	$	(1,062.0	)	$	3,632.7
Operating margin (1)	$	938.2	$	920.5	$	(55.6	)	$	—		$	1,803.1	$	275.1	$	348.7	$	1.5
Other financial information:
Total assets (2)	$	8,560.6	$	7,180.5	$	42.3		$	189.3		$	15,972.7	$	8,635.2	$	6,743.9	$	90.8	$	178.5		$	15,648.4
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	265.4	$	42.0	$	—		$	9.1		$	316.5	$	69.5	$	10.4	$	—	$	3.5		$	83.4

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,
	2021			2020		2021			2020		2022			2021
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	916.1		$	351.1	$	2,371.3		$	893.9	$	964.3		$	841.4
NGL		3,185.0			1,312.9		8,278.4			3,382.0		3,806.5			2,594.4
Condensate and crude oil		100.7			54.4		256.2			217.8		118.1			66.6
Petroleum products		—			13.2		—			69.8
		4,201.8			1,731.6		10,905.9			4,563.5		4,888.9			3,502.4
Non-customer revenue:
Derivative activities - Hedge		(100.4	)		19.2		(303.8	)		139.4		(145.7	)		(149.7	)
Derivative activities - Non-hedge (1)		16.7			90.0		(24.8	)		197.9		(177.0	)		15.0
		(83.7	)		109.2		(328.6	)		337.3		(322.7	)		(134.7	)
Total sales of commodities		4,118.1			1,840.8		10,577.3			4,900.8		4,566.2			3,367.7

Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		201.3			123.7		485.7			347.1		206.0			116.3
NGL transportation, fractionation and services		45.8			43.8		138.5			116.7		65.8			47.2
Storage, terminaling and export		87.7			96.6		273.1			285.5		100.9			88.8
Other		6.8			10.2		33.6			37.4		20.2			12.7
Total fees from midstream services		341.6			274.3		930.9			786.7		392.9			265.0

Total revenues	$	4,459.7		$	2,115.1	$	11,508.2		$	5,687.5	$	4,959.1		$	3,632.7

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2021			2020			2022			2021
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	361.4		$	261.0		$	938.2		$	753.7		$	397.6		$	275.1
Logistics and Transportation operating margin		280.7			280.4			920.5			806.0			352.1			348.7
Other operating margin		13.5			88.6			(55.6	)		215.9			(178.3	)		1.5
Depreciation and amortization expense		(222.8	)		(203.7	)		(650.9	)		(647.3	)		(209.1	)		(216.2	)
General and administrative expense		(67.3	)		(58.6	)		(192.4	)		(180.6	)		(67.1	)		(61.4	)
Impairment of long-lived assets		—			—			—			(2,442.8	)
Interest expense, net		(91.0	)		(97.7	)		(284.2	)		(292.4	)		(93.6	)		(98.4	)
Equity earnings (loss)		14.3			18.6			38.9			54.1			5.6			11.8
Gain (loss) on sale or disposition of business and assets		1.5			(58.0	)		1.7			(58.0	)
Gain (loss) on sale or disposition of assets														1.0			—
Write-down of assets		(0.5	)		(13.5	)		(5.0	)		(13.5	)		(0.5	)		(3.5	)
Gain (loss) from financing activities		—			(13.7	)		(16.6	)		47.4			(15.8	)		(14.7	)
Other, net		0.2			0.7			0.2			(0.1	)		(0.4	)		—
Income (loss) before income taxes	$	290.0		$	204.1		$	694.8		$	(1,757.6	)	$	191.5		$	242.9

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, ~~2020~~2021 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.

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

Our Logistics and 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 and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our ~~downstream~~Downstream facilities in Mont Belvieu, Texas, as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points.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 unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

In ~~November 2020,~~August 2021, we announced the ~~transfer~~construction of an existing cryogenic natural gas processing plant from our North Texas system (the “Longhorn Plant”), to our Permian Midland system. The plant was relocated to and installed in Reagan County, Texas, in 2021, as a new ~~200~~275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the ~~“Heim Plant”~~“Legacy plant”). The ~~Heim Plant, which commenced~~Legacy plant is expected to begin operations in the ~~third~~fourth quarter of ~~2021, processes natural gas production from the Permian Basin.~~2022.

In ~~August 2021,~~February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new ~~250~~275 MMcf/d cryogenic natural gas processing plant in ~~the~~Permian Midland ~~Basin~~ (the “Legacy ~~Plant”~~II plant”). The Legacy ~~Plant~~II plant is expected to begin operations in the ~~fourth~~second quarter of ~~2022.~~2023.

In ~~November 2021,~~February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced ~~that we were ordering long-lead items for our next potential~~the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian ~~Midland~~Delaware (the “Midway plant”). The Midway plant is expected to ~~meet~~begin operations in the ~~future infrastructure needs~~third quarter of ~~our producers given our expectation for increasing production beyond~~2023. In conjunction with the ~~Legacy Plant.~~commencement of operations of the Midway plant, we expect to idle the Sand Hills plant.

In ~~November 2021,~~January 2022, we ~~announced an update to our capital allocation strategy, including that for~~closed on the ~~fourth quarter~~purchase of ~~2021, we intend to recommend to our board~~all of directors an increase to our common dividend to $0.35 per common share or $1.40 per common share annualized. The initial recommended common dividend per share increase is expected to be effective for the fourth quarter of 2021 and payable in February 2022. We expect to continue to simplify our capital structure through repurchase of ourStonepeak Infrastructure Partners’ (“Stonepeak”) interests in our development company joint ventures ~~from investment vehicles affiliated with Stonepeak Infrastructure Partners~~(“DevCo JVs”) for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75% interest in Grand Prix Pipeline LLC, a 100% interest in our Train 6 fractionator in Mont Belvieu, Texas and owned a 25% equity interest in Gulf Coast Express Pipeline (“GCX”), prior to the GCX Sale (as defined below) in February 2022. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was $53.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

In February 2022, we announced that we executed agreements to sell Targa GCX Pipeline LLC, which held our 25 percent equity interest in GCX, for approximately ~~$925~~$857 million (the “GCX Sale”). We expect to receive the full proceeds from the sale in ~~January~~the second quarter of 2022 as the customary call right period has now expired.

In April 2022, we closed on the bolt-on acquisition of Southcross Energy Operating LLC and its subsidiaries in South Texas for a purchase price of approximately $200 million. We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the ~~redemption~~remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and which we will prospectively consolidate. See Note 4 - Joint Ventures, Acquisitions and Divestitures and Note 6 - Investments in Unconsolidated Affiliates to our Consolidated Financial Statements.

In the first quarter of 2022, we repurchased 737,799 shares of our common stock at a weighted average price of $67.37 for a total net cost of $49.7 million. There was $318.8 million remaining under our $500 million common share repurchase program as of March 31, 2022.

In May 2022, we redeemed in full all of our issued and outstanding shares of ~~our~~ Series A Preferred ~~Stock (“~~at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, which will be recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A ~~Preferred”) over time, once~~Preferred outstanding and all rights of the ~~redemption price steps down in March 2022, while continuing~~holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to ~~invest in accretive growth opportunities across~~ our ~~core integrated strategy. We also may opportunistically repurchase common stock under our existing $500 million authorized share repurchase program (the “Share Repurchase Program”).~~

In February ~~2021,~~2022, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto (the “TRGP Revolver”). The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver, including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures in February 2027. In February 2022, TRGP and the Partnership ~~issued $1.0~~received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc. (“Fitch”), and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder. In connection with our entry into the TRGP Revolver, we terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of March 31, 2022, $6.0 billion of 4%the Partnership Issuers’ senior unsecured notes was outstanding.

In March 2022, the Partnership redeemed all of the outstanding 5.375% Senior Notes due ~~2032,~~2027 (the “5.375% Notes”) with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the “4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds of approximately ~~$991 million.~~$1.5 billion. A portion of the net proceeds from the issuance were used to fund the ~~concurrent cash tender offer (the “February~~March Tender ~~Offer”)~~Offer and the subsequent redemption payment ~~for~~of the Partnership’s ~~5⅛% Senior~~5.875% Notes, ~~due 2025 (the “5⅛% Notes”),~~ with the remainder used for repayment of borrowings under the ~~Partnership’s senior secured revolving credit facility (the “TRP Revolver”) and our senior secured revolving credit facility (the “TRC Revolver”)~~.TRGP Revolver. As a result of the ~~February~~March Tender Offer and the subsequent redemption of the ~~5⅛%~~5.875% Notes, we ~~recorded~~will record a loss due to debt extinguishment of ~~$14.9~~$33.5 million ~~comprised~~in the second quarter of ~~$12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs.~~2022.

~~Additionally, Targa Pipeline Partners LP (“TPL”) redeemed all of~~In April 2022, the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023 (collectively, the “TPL Notes”) on February 22, 2021 with available liquidity under the TRP Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.

~~The~~ Partnership redeemed all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Notes”) on May 17, 2021 with available liquidity under the TRP Revolver. As a result of the redemption of the 4¼% Notes, we recorded a loss due to debt extinguishment of $1.9 million.

~~We or the Partnership~~ 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. Additionally, we may redeem all or a portion of our Series A Preferred in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions. Such repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

~~On April 21, 2021, we~~ amended the ~~Partnership’s accounts receivable securitization facility (the “Securitization Facility”)~~Securitization Facility to, ~~increase the facility size from $350.0 million to $400.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to~~among other things, extend the facility termination date to April ~~21, 2022.~~19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.

For additional information about our debt-related transactions, see Note 57 - Debt Obligations to our ~~consolidated financial statements.~~Consolidated Financial Statements.

The global spread of COVID-19 during 2020 and 2021 ~~has~~ caused significant commodity market volatility. ~~We are currently experiencing no material issues with potential workforce, supply chain or customer relationship disruptions.~~ Although significant progress has been made towards the development, distribution and administration of various COVID-19 vaccines, there continues to be significant uncertainty about the disruptions and other effects related to COVID-19. As a result, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

In February 2021, the Central region of the United States experienced unprecedented cold temperatures during a major winter storm that disrupted production operations, midstream infrastructure and many other services. This extreme weather caused wide fluctuations in commodity prices, short-term disruptions to ~~Targa’s~~our operations across Texas, New Mexico, Oklahoma and Louisiana, including

reduced throughput volumes coming into our systems, and adversely affected the operations and financial condition of some of our counterparties. Though certain ~~Company~~of our facilities experienced temporary outages, all facilities have since returned to full ~~operations~~operation without sustaining any long-term impacts or significant adverse financial impacts related to the weather event, and throughput volumes have returned to pre-storm levels. The full financial impact of the winter storm still remains uncertain as it is subject to recently proposed regulatory changes and potential customer and counterparty risk. ~~For further discussion, see “Item 1A. Risk Factors.”~~

In January 2022, the IRS notified us ~~on April 3, 2019,~~ that it will examine Targa’s ~~federal income~~net operating loss (“NOL”) carryback previously claimed under the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. The CARES Act was signed into law on March 27, 2020 and provided corporate taxpayers an expanded five-year NOL carryback period for losses generated in tax ~~returns (Form 1120) for 2014, 2015~~years 2018 through 2020. We received a cash refund of approximately $44 million related to the CARES Act provisions in 2020. We are in the process of responding to information requests from the IRS and 2016. The IRS completed their examination without proposing any adjustments, and the Joint Committee on Taxation approved the IRS’ findings without any exception. The Joint Committee on Taxation sent Targa a closing letter dated February 23, 2021. The closing letter effectively ends the IRS’ audit of Targa’s federal income tax returns for 2014, 2015 and 2016.do not anticipate material changes in prior year taxable income.

On January 20, 2022, FERC issued an order on rehearing of its December 17, 2020 ~~FERC issued an~~ Order Establishing Index Level ~~establishing an index level of~~in which the Producer Price Index for Finished Goods plus 0.78% for the five-year period commencing July 1, 2021, and ending June 30, 2026 (“December 2020 Order”). On May 14, 2021, FERC published a revised oil pricing index factor utilizingCommission reduced the oil pricing index factor ~~established in the December 2020 Order, resulting in a negative percent change~~for oil pipelines to use for the ~~index year~~current five-year period. As a result, the ceiling levels computed for July 1, 2021 ~~through~~to June 30, ~~2022. This means that~~2022, and the ~~ceiling level~~resulting rates currently in effect for certain ~~oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate must decrease~~of Targa’s liquids pipelines were recomputed to ~~be equal to or less than the applicable ceiling. However, a number of our pipeline rates, including all rates on Grand Prix Pipeline LLC~~ ~~(“Grand Prix Joint Venture”)~~ and Targa Gulf Coast NGL Pipeline LLC, and certain rates on Targa NGL Pipeline Company LLC had not been adjusted in a number of years, and, therefore, these pipelines increased their rates to equal the applicable new ceiling level. Certain rates on the Targa NGL Pipeline Company LLC system were reduced to equal the ceiling level. However, requests for rehearing of the December 2020 Order were filed with FERC, and those requests remain pending, with rehearing granted for purposes of extending the time FERC has to review these requests. FERC’s final application of its indexing rate methodologyaccount for the ~~next five-year term of~~reduced index rates will be determined based on the outcome of these requests for rehearing, and any changes to FERC’s index level may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.factor.

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies into 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, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, 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 capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our ~~downstream~~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 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: adjusted ~~gross margin, adjusted operating margin, adjusted~~ EBITDA, distributable cash flow, ~~and~~ adjusted free cash ~~flow.~~

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 adjusted 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 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 and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses 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.

Our capital expenditures are classified as growth capital expenditures 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.

Capital spending associated with growth and maintenance projects is 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 utilize non-GAAP measures to analyze our performance. Adjusted ~~gross margin, adjusted operating margin, adjusted~~ EBITDA, distributable cash flow, ~~and~~ adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP ~~measure~~measures most directly comparable to these non-GAAP measures are ~~gross margin,~~ income (loss) from operations, ~~and net~~Net income (loss) attributable to ~~TRC.~~Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to ~~the comparable~~ GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect ~~net~~ income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

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

Gathering and Processing ~~segment~~ adjusted ~~gross~~operating margin consists primarily of:

Logistics and Transportation ~~segment~~ adjusted ~~gross~~operating margin consists primarily of:

The adjusted ~~gross~~operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.

~~We define adjusted~~ operating margin ~~as adjusted gross margin less operating expenses. Adjusted operating margin is an important performance measure of the core profitability of~~for our ~~operations. Adjusted gross margin and adjusted operating margin provide~~segments provides useful information to investors because ~~they are~~it is used as a supplemental financial ~~measures~~measure by management and by external users of our financial statements, including investors and commercial banks, to assess:

Management reviews ~~business segment~~ adjusted ~~gross~~operating margin and operating margin for our segments 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. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”

We define adjusted EBITDA as ~~net~~Net income (loss) attributable to ~~TRC~~Targa Resources Corp. 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 to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

We define distributable cash flow as adjusted EBITDA less ~~distributions to TRP preferred limited partners,~~ cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). ~~The Preferred~~ ~~Units~~ ~~that were issued by the Partnership in October 2015 were redeemed in December 2020, and are no longer outstanding.~~ We define adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

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,
	2021			2020			2021				2020			2022			2021
	(In millions)													(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to TRC	$	182.2		$	69.3		$		384.8		$	(1,587.5	)
Income attributable to TRP preferred limited partners		—			2.8				—			8.4
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.														$	88.0		$	146.4
Interest (income) expense, net		91.0			97.7				284.2			292.4			93.6			98.4
Income tax expense (benefit)		2.0			31.9				23.5			(286.6	)		22.9			15.0
Depreciation and amortization expense		222.8			203.7				650.9			647.3			209.1			216.2
Impairment of long-lived assets		—			—				—			2,442.8
(Gain) loss on sale or disposition of business and assets		(1.5	)		58.0				(1.7	)		58.0
(Gain) loss on sale or disposition of assets															(1.0	)		—
Write-down of assets		0.5			13.5				5.0			13.5			0.5			3.5
(Gain) loss from financing activities (1)		—			13.7				16.6			(47.4	)		15.8			14.7
Equity (earnings) loss		(14.3	)		(18.6	)			(38.9	)		(54.1	)		(5.6	)		(11.8	)
Distributions from unconsolidated affiliates and preferred partner interests, net		28.2			28.2				88.4			81.6			12.5			33.3
Compensation on equity grants		14.7			16.4				44.6			49.5			13.5			15.0
Risk management activities		(12.6	)		(88.3	)			55.6			(214.2	)		178.2			(1.5	)
Severance and related benefits		—			—				—			6.5
Noncontrolling interests adjustments (2)		(7.1	)		(9.2	)			(31.6	)		(211.7	)		(1.7	)		(13.5	)
TRC Adjusted EBITDA	$	505.9		$	419.1		$		1,481.4		$	1,198.5
Distributions to TRP preferred limited partners		—			(2.8	)			—			(8.4	)
Adjusted EBITDA														$	625.8		$	515.7
Interest expense on debt obligations (3)		(91.6	)		(98.2	)			(285.8	)		(289.5	)		(91.7	)		(98.8	)
Maintenance capital expenditures		(31.1	)		(27.3	)			(78.4	)		(67.7	)
Noncontrolling interests adjustments of maintenance capital expenditures		1.5			3.9				5.5			1.6
Maintenance capital expenditures, net (4)															(37.7	)		(19.0	)
Cash taxes		(0.8	)		—				(2.0	)		44.4			(1.8	)		(0.5	)
Distributable Cash Flow	$	383.9		$	294.7		$		1,120.7		$	878.9		$	494.6		$	397.4
Growth capital expenditures, net (4)		(86.7	)		(105.4	)			(227.9	)		(518.5	)		(121.4	)		(61.0	)
Adjusted Free Cash Flow	$	297.2		$	189.3		$		892.8		$	360.4		$	373.2		$	336.4

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,
	2021			2020			2021 vs. 2020						2021			2020			2021 vs. 2020						2022			2021			2022 vs. 2021
	(In millions)																								(In millions)
Revenues:
Sales of commodities	$	4,118.1		$	1,840.8		$	2,277.3			124	%	$	10,577.3		$	4,900.8		$	5,676.5			116	%	$	4,566.2		$	3,367.7		$	1,198.5			36	%
Fees from midstream services		341.6			274.3			67.3			25	%		930.9			786.7			144.2			18	%		392.9			265.0			127.9			48	%
Total revenues		4,459.7			2,115.1			2,344.6			111	%		11,508.2			5,687.5			5,820.7			102	%		4,959.1			3,632.7			1,326.4			37	%
Product purchases and fuel ~~(1)~~		3,614.7			1,322.9			2,291.8			173	%		9,159.8			3,405.1			5,754.7			169	%		4,204.1			2,836.3			1,367.8			48	%
Operating expenses ~~(1)~~		189.4			162.2			27.2			17	%		545.3			506.8			38.5			8	%		183.5			171.1			12.4			7	%
Depreciation and amortization expense		222.8			203.7			19.1			9	%		650.9			647.3			3.6			1	%		209.1			216.2			(7.1	)		(3	%)
General and administrative expense		67.3			58.6			8.7			15	%		192.4			180.6			11.8			7	%		67.1			61.4			5.7			9	%
Impairment of long-lived assets		—			—			—			—			—			2,442.8			(2,442.8	)		(100	%)
Other operating (income) expense		(1.0	)		72.2			(73.2	)		(101	%)		3.4			73.8			(70.4	)		(95	%)		(0.5	)		3.6			(4.1	)		(114	%)
Income (loss) from operations		366.5			295.5			71.0			24	%		956.4			(1,568.9	)		2,525.3			161	%		295.8			344.1			(48.3	)		(14	%)
Interest expense, net		(91.0	)		(97.7	)		6.7			7	%		(284.2	)		(292.4	)		8.2			3	%		(93.6	)		(98.4	)		4.8			5	%
Equity earnings (loss)		14.3			18.6			(4.3	)		(23	%)		38.9			54.1			(15.2	)		(28	%)		5.6			11.8			(6.2	)		(53	%)
Gain (loss) from financing activities		—			(13.7	)		13.7			100	%		(16.6	)		47.4			(64.0	)		(135	%)		(15.8	)		(14.7	)		(1.1	)		7	%
Other, net		0.2			1.4			(1.2	)	NM				0.3			2.2			(1.9	)	NM				(0.5	)		0.1			(0.6	)	NM
Income tax (expense) benefit		(2.0	)		(31.9	)		29.9			94	%		(23.5	)		286.6			(310.1	)		(108	%)		(22.9	)		(15.0	)		(7.9	)		53	%
Net income (loss)		288.0			172.2			115.8			67	%		671.3			(1,471.0	)		2,142.3			146	%		168.6			227.9			(59.3	)		(26	%)
Less: Net income (loss) attributable to noncontrolling interests		105.8			102.9			2.9			3	%		286.5			116.5			170.0			146	%		80.6			81.5			(0.9	)		(1	%)
Net income (loss) attributable to Targa Resources Corp.		182.2			69.3			112.9			163	%		384.8			(1,587.5	)		1,972.3			124	%		88.0			146.4			(58.4	)		(40	%)
Premium on repurchase of noncontrolling interests, net of tax																										53.1			—			53.1			100	%
Dividends on Series A Preferred Stock		21.8			22.9			(1.1	)		(5	%)		65.5			68.8			(3.3	)		(5	%)		21.8			21.8			—			—
Deemed dividends on Series A Preferred Stock		—			9.5			(9.5	)		(100	%)		—			27.7			(27.7	)		(100	%)
Net income (loss) attributable to common shareholders	$	160.4		$	36.9		$	123.5		NM			$	319.3		$	(1,684.0	)	$	2,003.3			119	%	$	13.1		$	124.6		$	(111.5	)		(89	%)
Financial data:
Adjusted EBITDA (2)	$	505.9		$	419.1		$	86.8			21	%	$	1,481.4		$	1,198.5		$	282.9			24	%
Distributable cash flow (2)		383.9			294.7			89.2			30	%		1,120.7			878.9			241.8			28	%
Adjusted free cash flow (2)		297.2			189.3			107.9			57	%		892.8			360.4			532.4			148	%
Adjusted EBITDA (1)																									$	625.8		$	515.7		$	110.1			21	%
Distributable cash flow (1)																										494.6			397.4			97.2			24	%
Adjusted free cash flow (1)																										373.2			336.4			36.8			11	%

Three Months Ended ~~September 30, 2021~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2020~~March 31, 2021

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($~~2,259.0~~1,385.7 million) and higher ~~NGL and~~ natural gas volumes ($~~226.6~~20.3 million), partially offset by lower NGL volumes ($20.2 million) and the unfavorable impact of hedges ($~~192.8~~188.0 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, ~~partially offset by lower terminaling~~transportation and ~~storage fees.~~fractionation fees and export volumes.

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher ~~NGL and~~ natural gas volumes, partially offset by lower NGL volumes.

~~Operating~~The increase in operating expenses ~~were higher~~was due to ~~increased~~higher labor ~~costs and higher repairs~~ and maintenance costs primarily due to increased activity ~~levels~~ and system ~~expansions.~~expansions, partially offset by lower taxes and the reduction in expense from a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana during the first quarter of 2021.

See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.

The ~~increase~~decrease in depreciation and amortization expense is primarily due to a ~~full~~lower depreciable base associated with assets that were impaired during the fourth quarter of depreciation on major growth capital projects previously placed in service, including the addition of fractionation trains in Mont Belvieu, Texas and additional processing plants and associated infrastructure in the Permian Basin. The increase in depreciation and amortization expense was partially offset by the sale of assets in Channelview, Texas, in October 2020.

~~The increase in general and administrative expense is primarily due to higher compensation and benefits and an increase in insurance costs.~~

Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.

~~The decrease in interest expense, net is primarily due to lower net borrowings, partially offset by lower capitalized interest~~ ~~resulting from lower growth capital investments~~.

~~During the third quarter of 2020, the Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.~~

~~The decrease in income tax expense is primarily due to a larger release of the valuation allowance in 2021 compared to 2020.~~

~~The decrease in dividends on Series A Preferred is due to the partial repurchase of our Series A Preferred in December 2020.~~

~~The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06,~~ Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity~~, which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.~~

~~Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020~~

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($5,840.0 million) and higher NGL and natural gas volumes ($650.5 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($148.0 million) and the unfavorable impact of hedges ($666.0 million).

~~The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, partially offset by lower terminaling and storage fees.~~

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes, partially offset by lower petroleum products, crude marketing and condensate volumes.

~~Operating expenses were higher due to increased labor costs, higher repairs and maintenance and higher ad valorem taxes primarily due to increased activity levels and system expansions.~~

~~See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.~~2021.

The increase in general and administrative expense is primarily due to higher ~~compensation and benefits and an increase in~~ insurance costs ~~partially offset by a decrease in~~and professional fees.

In 2020, we recognized a non-cash pre-tax impairment charge of $2,442.8 million, primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations.

The decrease in interest expense, net is primarily due to lower net borrowings ~~partially offset by lower~~and an increase in capitalized interest resulting from ~~lower~~higher growth capital investments.

The decrease in equity earnings is primarily due to lower earnings from our investments in GCX DevCo JV and the Badlands, partially offset by lower losses from our investments in Gulf Coast Fractionators, T2 Eagle Ford Gathering Company L.L.C. and ~~Cayenne Pipeline LLC, partially offset by an increase~~T2 LaSalle Gathering Company L.L.C. Lower equity earnings from ~~Little Missouri~~our investments in GCX DevCo JV were due to the DevCo JV Repurchase in 2022. See Note 4 ~~LLC (“Little Missouri 4”).~~– Investments in Joint Ventures, Divestitures and Acquisitions to our Consolidated Financial Statements for further discussion.

During ~~2021,~~2022, we terminated the Previous TRGP Revolver and the Partnership Revolver, and the Partnership redeemed the ~~5⅛% Notes, the TPL Notes and the 4¼%~~5.375% Notes, resulting in a ~~$16.6 million~~ net loss from financing activities. During ~~2020,~~2021, the Partnership ~~repurchased a portion of~~redeemed its ~~outstanding senior notes on~~5.125% Senior Notes due 2025, the ~~open market,~~Targa Pipeline Partners LP (“TPL”) 4.750% Senior Notes due 2021 and the TPL 5.875% Senior Notes due 2023, resulting in a ~~$47.4 million~~ net ~~gain~~loss from financing activities. See Note 7 – Debt Obligations for further discussion.

The increase in income tax expense is primarily due to ~~an increase~~a smaller release of the valuation allowance in ~~pre-tax book income,~~2022 compared to 2021, partially offset by a decrease in ~~the valuation allowance.~~pre-tax book income.

~~The increase in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling interest holders in~~During the first quarter of ~~2020 and higher income allocated to noncontrolling interest holders~~2022, we closed on the purchase of all of Stonepeak’s interests in ~~Grand Prix Joint Venture.~~our DevCo JVs for $926.3 million. The ~~increase~~change in ~~net income attributable to~~our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests ~~was partially offset by the impact of the redemption of the Partnership’s preferred units~~resulting in ~~December 2020.~~

~~The decrease in dividends~~a $53.1 million premium on ~~Series A Preferred is due to the partial~~ repurchase of noncontrolling interests, net of tax. See Note 4 – Joint Ventures, Divestitures and Acquisitions to our ~~Series A Preferred in December 2020.~~

~~The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06,~~ ~~Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting~~Consolidated Financial Statements for ~~Convertible Instruments and Contracts in an Entity’s Own Equity~~further discussion~~, which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.~~.

	Three Months Ended September 30,										Nine Months Ended September 30,									Three Months Ended March 31,
	2021			2020		2021 vs. 2020					2021		2020		2021 vs. 2020					2022			2021		2022 vs. 2021
		(In millions, except operating statistics and price amounts)																			(In millions, except operating statistics and price amounts)
Operating margin	$		361.4	$	261.0	$	100.4		38	%	$	938.2	$	753.7	$	184.5		24	%	$		397.6	$	275.1	$	122.5		45	%
Operating expenses ~~(1)~~			122.8		102.1		20.7		20	%		343.1		313.6		29.5		9	%			116.6		105.5		11.1		11	%
Adjusted gross margin (1)	$		484.2	$	363.1	$	121.1		33	%	$	1,281.3	$	1,067.3	$	214.0		20	%
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3),(4)
Adjusted operating margin																				$		514.2	$	380.6	$	133.6		35	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland ~~(5)~~(4)			2,109.2		1,811.5		297.7		16	%		1,900.7		1,722.1		178.6		10	%			2,075.1		1,658.3		416.8		25	%
Permian Delaware			842.7		758.1		84.6		11	%		805.9		712.4		93.5		13	%			977.0		737.6		239.4		32	%
Total Permian			2,951.9		2,569.6		382.3					2,706.6		2,434.5		272.1						3,052.1		2,395.9		656.2

SouthTX(5)			180.5		233.6		(53.1	)	(23	%)		184.0		261.5		(77.5	)	(30	%)			162.1		176.4		(14.3	)	(8	%)
North Texas			180.7		197.8		(17.1	)	(9	%)		179.2		206.3		(27.1	)	(13	%)			175.3		175.4		(0.1	)	—
SouthOK(5)			420.6		386.9		33.7		9	%		402.6		463.3		(60.7	)	(13	%)			407.3		375.2		32.1		9	%
WestOK			219.4		233.6		(14.2	)	(6	%)		211.6		258.7		(47.1	)	(18	%)			202.5		202.7		(0.2	)	—
Total Central			1,001.2		1,051.9		(50.7	)				977.4		1,189.8		(212.4	)					947.2		929.7		17.5

Badlands (6)			135.2		137.0		(1.8	)	(1	%)		137.8		136.1		1.7		1	%
Badlands (5) (6)																						125.0		134.9		(9.9	)	(7	%)
Total Field			4,088.3		3,758.5		329.8					3,821.8		3,760.4		61.4						4,124.3		3,460.5		663.8

Coastal			527.1		522.8		4.3		1	%		598.3		672.9		(74.6	)	(11	%)			602.1		652.6		(50.5	)	(8	%)

Total			4,615.4		4,281.3		334.1		8	%		4,420.1		4,433.3		(13.2	)	—				4,726.4		4,113.1		613.3		15	%
NGL production, MBbl/d ~~(4)~~(3)
Permian Midland ~~(5)~~(4)			307.3		253.0		54.3		21	%		274.8		247.6		27.2		11	%			300.8		237.0		63.8		27	%
Permian Delaware			119.8		105.3		14.5		14	%		109.3		97.1		12.2		13	%			129.8		96.5		33.3		35	%
Total Permian			427.1		358.3		68.8					384.1		344.7		39.4						430.6		333.5		97.1

SouthTX(5)			24.2		29.2		(5.0	)	(17	%)		22.6		28.7		(6.1	)	(21	%)			20.3		17.6		2.7		15	%
North Texas			21.0		23.7		(2.7	)	(11	%)		20.2		24.5		(4.3	)	(18	%)			19.2		19.2		—		—
SouthOK(5)			52.1		45.9		6.2		14	%		48.8		54.6		(5.8	)	(11	%)			50.5		43.8		6.7		15	%
WestOK			15.7		19.3		(3.6	)	(19	%)		16.2		21.2		(5.0	)	(24	%)			14.9		16.1		(1.2	)	(7	%)
Total Central			113.0		118.1		(5.1	)				107.8		129.0		(21.2	)					104.9		96.7		8.2

Badlands(5)			16.2		17.0		(0.8	)	(5	%)		16.0		16.3		(0.3	)	(2	%)			14.7		15.5		(0.8	)	(5	%)
Total Field			556.3		493.4		62.9					507.9		490.0		17.9						550.2		445.7		104.5

Coastal			28.0		32.5		(4.5	)	(14	%)		34.5		41.5		(7.0	)	(17	%)			37.1		40.0		(2.9	)	(7	%)

Total			584.3		525.9		58.4		11	%		542.4		531.5		10.9		2	%			587.3		485.7		101.6		21	%
Crude oil, Badlands, MBbl/d			140.8		146.4		(5.6	)	(4	%)		138.7		160.4		(21.7	)	(14	%)			122.7		136.2		(13.5	)	(10	%)
Crude oil, Permian, MBbl/d			34.1		44.6		(10.5	)	(24	%)		35.3		45.3		(10.0	)	(22	%)			30.6		34.9		(4.3	)	(12	%)
Natural gas sales, BBtu/d ~~(4)~~(3)			2,319.9		2,032.3		287.6		14	%		2,162.5		2,079.3		83.2		4	%			2,126.3		1,956.0		170.3		9	%
NGL sales, MBbl/d ~~(4)~~(3)			412.6		389.5		23.1		6	%		384.7		406.0		(21.3	)	(5	%)			424.8		349.0		75.8		22	%
Condensate sales, MBbl/d			15.4		13.6		1.8		13	%		15.3		16.1		(0.8	)	(5	%)			14.4		15.2		(0.8	)	(5	%)
Average realized prices - inclusive of hedges (7):
Natural gas, $/MMBtu			3.51		1.34		2.17		162	%		2.85		1.10		1.75		159	%			4.09		2.51		1.58		63	%
NGL, $/gal			0.69		0.29		0.40		138	%		0.56		0.24		0.32		133	%			0.79		0.46		0.33		72	%
Condensate, $/Bbl			64.41		43.49		20.92		48	%		56.86		38.56		18.30		47	%			75.72		46.80		28.92		62	%

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

	Nine Months Ended September 30, 2021								Nine Months Ended September 30, 2020						Three Months Ended March 31, 2022								Three Months Ended March 31, 2021
	(In millions, except volumetric data and price amounts)														(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)		Gain (Loss)		Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		56.6	$	(1.01	)	$	(57.2	)		50.6	$	0.55	$	27.7		17.5	$	(1.78	)	$	(31.2	)		18.0	$	(0.72	)	$	(12.8	)
NGL (MMgal)		420.0		(0.24	)		(99.3	)		322.1		0.15		49.7		170.4		(0.46	)		(78.0	)		122.7		(0.19	)		(22.9	)
Crude oil (MBbl)		1.6		(11.38	)		(18.2	)		1.4		19.72		27.7		0.5		(39.40	)		(19.7	)		0.5		(4.00	)		(2.2	)
						$	(174.7	)					$	105.1						$	(128.9	)						$	(37.9	)

Three Months Ended ~~September 30, 2021~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2020~~March 31, 2021

The increase in adjusted ~~gross~~operating margin was due to higher realized commodity prices, ~~and higher~~ natural gas inlet volumes ~~resulting in increased margin primarily~~and fees predominantly in the ~~Permian, partially offset by lower volumes~~Permian. The increase in ~~the Central region. In the Permian,~~ natural gas inlet volumes ~~increased due~~in the Permian was attributable to higher production, ~~and~~higher producer activity ~~as well as~~and the addition of the ~~Gateway and~~ Heim ~~plants~~plant during the third ~~quarters~~quarter of ~~2020 and 2021, respectively. In the Badlands and Coastal regions,~~2021. Prior year natural gas inlet volumes were ~~relatively flat,~~impacted by the short-term operational disruption associated with a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana, that reduced our Permian and Central region volumes during the first quarter of 2021. In the Badlands, the decrease in volumes was attributable to lower production and the impact of winter weather, while lower volumes in the ~~Central~~Coastal region ~~the decrease was~~were due to lower production and continued low producer activity. ~~Total crude oil volumes decreased in the Badlands and the Permian due to lower production.~~

Operating expenses were higher due to increased activity levels in the Permian and the addition of the ~~Gateway and~~ Heim ~~plants in the third quarters of 2020 and 2021, respectively, which resulted in increased labor costs, materials and chemicals.~~

~~Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020~~

The increase in adjusted gross margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in higher margin primarily in the Permian, partially offset by the short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. In the Permian, natural gas inlet volumes increased due to higher production, higher producer activity, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant in the third quarter of 2021. In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal regions was due to continued low producer activity. Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

~~Operating expenses were higher due to increased activity levels in the Permian, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant~~plant in the third quarter of 2021, which resulted in increased labor costs, materials and ~~materials.~~chemicals.

	Three Months Ended September 30,								Nine Months Ended September 30,							Three Months Ended March 31,
	2021		2020		2021 vs. 2020				2021		2020		2021 vs. 2020			2022		2021		2022 vs. 2021
(In millions, except operating statistics and price amounts)
																(In millions, except operating statistics)
Operating margin	$	280.7	$	280.4	$	0.3		—	$	920.5	$	806.0	$	114.5	14%	$	352.1	$	348.7	$	3.4	1%
Operating expenses ~~(1)~~		67.3		61.7		5.6		9%		204.1		196.8		7.3	4%		66.9		65.8		1.1	2%
Adjusted gross margin (1)	$	348.0	$	342.1	$	5.9		2%	$	1,124.6	$	1,002.8	$	121.8	12%
Operating statistics MBbl/d (2):
Pipeline throughput (3)		416.5		300.9		115.6		38%		383.8		273.0		110.8	41%
Adjusted operating margin																$	419.0	$	414.5	$	4.5	1%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)																	459.7		342.5		117.2	34%
Fractionation volumes		662.0		589.5		72.5		12%		617.5		598.0		19.5	3%		702.8		545.8		157.0	29%
Export volumes ~~(4)~~(3)		293.2		308.5		(15.3	)	(5%)		305.7		277.2		28.5	10%		340.8		283.3		57.5	20%
NGL sales		857.3		724.1		133.2		18%		881.1		721.6		159.5	22%		872.8		827.3		45.5	5%

Three Months Ended ~~September 30, 2021~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2020~~March 31, 2021

The increase in adjusted ~~gross~~operating margin was primarily due to higher pipeline transportation and fractionation volumes ~~partially offset by lower~~and higher LPG export volumes, ~~and~~partially offset by lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems. ~~LPG export~~Prior year Downstream system volumes were ~~lower due to~~impacted by the short-term operational disruption and impacts associated with a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana, that reduced ~~short-term loading capacity as a result of repairs~~our Permian and ~~maintenance that were completed in~~Central region volumes during the ~~third~~first quarter of 2021. ~~Marketing~~Higher optimization margin ~~decreased due~~attributable to ~~fewer optimization opportunities.~~the winter storm resulted in higher marketing margin in the first quarter of 2021.

Operating expenses were slightly higher due to higher repairs and maintenance, increased system throughput expenses and higher ad valorem taxes primarily due to system expansions, partially offset by cost reduction measures and the sale of assets in Channelview, Texas, in 2020.maintenance.

~~Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020~~

The increase in adjusted gross margin was primarily due to higher pipeline transportation and fractionation volumes that benefited from higher supply volumes from our Permian Gathering and Processing systems, partially offset by short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. Other drivers included higher marketing margin due to greater optimization opportunities and higher LPG export volumes, partially offset by lower LPG export terminal fees.

Operating expenses were higher due to higher repairs and maintenance, increased system throughput expenses and higher ad valorem taxes primarily due to system expansions, partially offset by cost reduction measures and the sale of assets in Channelview, Texas, in 2020.

	Three Months Ended September 30,							Nine Months Ended September 30,								Three Months Ended March 31,
	2021		2020		2021 vs. 2020			2021			2020		2021 vs. 2020			2022			2021		2022 vs. 2021
	(In millions)															(In millions)
Operating margin	$	13.5	$	88.6	$	(75.1	)	$	(55.6	)	$	215.9	$	(271.5	)	$	(178.3	)	$	1.5	$	(179.8	)
Gross margin	$	13.5	$	88.6	$	(75.1	)	$	(55.6	)	$	215.9	$	(271.5	)
Adjusted operating margin																$	(178.3	)	$	1.5	$	(179.8	)

Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 3. – Quantitative and Qualitative Disclosures About Market Risk.”

As of ~~September 30, 2021,~~March 31, 2022, inclusive of our consolidated joint venture accounts, we had ~~$228.6~~$135.9 million of ~~“Cash~~Cash and cash ~~equivalents”~~equivalents on our Consolidated Balance Sheets. We believe our cash positions, our cash flows from operating activities, our free cash flow after dividends and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity ~~subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements,~~ as well as the ability to contribute capital to the ~~Partnership, subject to any restrictions contained in the covenants of our debt agreements.~~Partnership.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements and to pay dividends declared by our board of directors 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 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.”

We are entitled to the entirety of distributions made by the Partnership on its equity interests. The actual amount we declare as ~~distributions~~dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

The Partnership’s debt agreements may restrict or prohibit the payment of distributions if the Partnership is in default or threat of default. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock or Series A Preferred shares. In addition, so long as any of our Series A Preferred shares are outstanding, certain common stock distribution limitations exist.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the ~~TRC Revolver, the TRP~~TRGP Revolver and the Partnership’s Securitization Facility and access to debt and equity capital 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 facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Our short-term liquidity on a consolidated basis as of ~~October 29, 2021,~~May 3, 2022, was:

Other potential capital resources associated with our existing arrangements ~~include:~~

~~On April 21, 2021, we amended~~ the ~~Partnership’s Securitization Facility~~TRGP Revolver, subject to ~~increase~~ the facility size from $350.0 million to $400.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.terms therein. The TRGP Revolver matures on February 17, 2027.

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 Fitch, 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 capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Partnership’s Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.

Working capital as of ~~September 30, 2021~~March 31, 2022 decreased ~~$555.9~~$481.2 million compared to December 31, ~~2020.~~2021. The decrease was primarily due to higher product purchases ~~payable~~and fuel payables as a result of higher commodity prices, ~~and~~ an increase in the current liability position of our derivative contracts and higher net borrowing on the Securitization Facility, partially offset by higher receivables resulting from higher commodity ~~prices and an increase in NGLs inventory.~~prices.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the ~~TRC Revolver, the TRP~~TRGP Revolver and the Partnership’s Securitization Facility and proceeds from debt and equity 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 quarterly cash dividends for at least the next twelve months.

Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements.

In ~~2019,~~February 2022, we ~~closed on~~entered into the ~~sale~~TRGP Revolver with Bank of ~~a 45% interest in Targa Badlands LLC to GSO Capital Partners~~America, N.A., as the Administrative Agent, Collateral Agent and ~~Blackstone Tactical Opportunities. Targa Badlands LLC is a discrete entity~~Swing Line Lender, and the ~~assets and~~other lenders party thereto. The TRGP Revolver provides for a revolving credit ~~of Targa Badlands LLC are not available to satisfy the debts and other obligations of Targa or its other subsidiaries.~~

~~In February 2021, the Partnership issued $1.0 billion~~facility in an initial aggregate principal amount ~~of 4% Senior Notes due 2032 (the “4% Notes”), resulting~~up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to $500.0 million in ~~net proceeds of approximately $991 million. A portion~~the future, subject to the terms of the ~~net proceeds~~TRGP Revolver, including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures in February 2027. In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from S&P and Fitch, and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s. As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the ~~issuance were used to fund~~liens securing our obligations thereunder. In connection with our entry into the ~~February Tender Offer and subsequent redemption payment for~~TRGP Revolver, we terminated the ~~5⅛% Notes, with the remainder used for repayment of borrowings under the TRP~~Previous TRGP Revolver and ~~TRC~~the Partnership Revolver.As a result of the ~~February Tender Offer~~termination of the Previous TRGP Revolver and the ~~subsequent~~Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership Issuers under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of March 31, 2022, $6.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

In March 2022, the Partnership redeemed all of the outstanding 5.375% Notes with available liquidity under the TRGP Revolver. As a result of the redemption of the ~~5⅛%~~5.375% Notes, we recorded a loss due to debt extinguishment of ~~$14.9~~$15.0 million comprised of ~~$12.5~~$12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of $750.0 million aggregate principal amount of our 4.200% Notes and $750.0 million aggregate principal amount of our 4.950% Notes, resulting in net proceeds of approximately $1.5 billion. A portion of the ~~outstanding TPL~~net proceeds from the issuance were used to fund the concurrent March Tender Offer and the subsequent redemption payment of the Partnership’s 5.875% Notes, ~~on February 22, 2021~~ with ~~available liquidity~~the remainder used for repayment of borrowings under the ~~TRP~~TRGP Revolver. As a result of the ~~redemptions of~~March Tender Offer and the ~~TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.~~

~~The Partnership redeemed all of the outstanding 4¼% Notes on May 17, 2021 with available liquidity under the TRP Revolver. As a result of the~~subsequent redemption of the ~~4¼%~~5.875% Notes, we ~~recorded~~will record a loss due to debt extinguishment of ~~$1.9 million.~~$33.5 million during the second quarter of 2022.

WeIn April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.

In the future, we or the Partnership may ~~retire~~redeem, purchase or ~~purchase various series~~exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. ~~Additionally, we may redeem all or a portion of our Series A Preferred shares in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions.~~ Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

OnIn May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April ~~21, 2021,~~1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, which will be recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we ~~amended~~have no Series A Preferred outstanding and all rights of the ~~Securitization Facility~~holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to ~~increase the facility size from $350.0 million to $400.0 million to more closely align with~~ our ~~expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.~~Consolidated Financial Statements.

To date, our debt balances and our subsidiaries’ 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 57 - Debt Obligations to our ~~consolidated financial statements.~~Consolidated Financial Statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

As of ~~September 30, 2021,~~March 31, 2022, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Nine Months Ended September 30,
2021		2020		2021 vs. 2020
Three Months Ended March 31,						Three Months Ended March 31,
2022						2022	2021		2022 vs. 2021
(In millions)	(In millions)					(In millions)
$	1,798.8	$	1,095.7	$	703.1	748.2	$	679.8	$	68.4

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs and natural gas, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital 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~~The increase in net cash provided by operations ~~increased in 2021 compared to 2020~~was primarily due to higher commodity prices, resulting in higher collections from customers, partially offset by ~~higher~~an increase in payments for product purchases and fuel and hedge transactions.

Nine Months Ended September 30,
2021			2020			2021 vs. 2020
Three Months Ended March 31,								Three Months Ended March 31,
2022								2022		2021			2022 vs. 2021
(In millions)	(In millions)							(In millions)
$	(299.6	)	$	(654.0	)	$	354.4	(197.0	)	$	(90.0	)	$	(107.0	)

The increase in net cash used in investing activities ~~decreased in 2021 compared to 2020,~~was primarily due to ~~lower~~higher outlays for property, plant and equipment ~~of $481.5 million,~~ resulting from construction activities of the ~~completion of additional fractionation trains in Mont Belvieu, Texas (collectively, “Trains 7~~Legacy, Legacy II and 8”), the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and additional processing plants and associated infrastructure in the Permian Basin in 2020, partially offset by higher proceeds from the sale of business and assets of $128.0 million including from the sale of our Delaware crude system in 2020.Midway plants.

	Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2022			2021
	(In millions)						(In millions)
Source of Financing Activities, net
Repurchase of noncontrolling interests							$	(926.3	)	$	—
Debt, including financing costs	$	(996.0	)	$	130.1			620.2			(400.2	)
Dividends and distributions								(108.0	)		(48.0	)
Contributions from (distributions to) noncontrolling interests		(364.1	)		(277.3	)		(87.5	)		(127.3	)
Dividends and distributions		(140.2	)		(345.1	)
Other		(13.1	)		(5.5	)		(72.2	)		(8.6	)
Net cash provided by (used in) financing activities	$	(1,513.4	)	$	(497.8	)	$	(573.8	)	$	(584.1	)

In ~~2021~~,The decrease in net cash used in financing activities iswas primarily due to ~~repayments~~ higher borrowings of debt ~~including repayment of borrowings under the TRP Revolver~~ and ~~TRC Revolver and the redemptions of the 5⅛% Notes,~~ ~~TPL Notes and 4¼% Notes,~~ ~~net distributions to noncontrolling interests and payments of dividends to our common and Series A Preferred shareholders, partially offset by borrowings, including the issuance of the 4% Notes.~~

~~In 2020, net cash used in financing activities is primarily due to payments of dividends to our common and Series A Preferred shareholders, and net~~lower distributions to noncontrolling interests, partially offset by ~~a net~~the repurchase of the non-controlling interests in the DevCo JVs, and higher dividends and distributions paid in 2022. The higher dividends and distributions were due to the increase of ~~debt outstanding.~~ our common dividends from $0.10 to $0.35 in January 2022.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Our ~~debt outstanding increased due~~subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior notes, subject to ~~net borrowings under our credit facilities, partially offset by redemptions~~certain limited exceptions.

In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and ~~repurchases~~Statement of ~~a portion~~Operations information for the Obligated Group based on Rule 13-01 of the ~~outstanding senior notes of~~SEC’s Regulation S-X.

All significant intercompany items among the ~~Partnership.~~Obligated Group have been eliminated in the supplemental summarized combined financial information. TheObligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information.Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”),are presented separately in the following supplemental summarized combined financial information.

Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group follows:

The following table details the dividends on common stock declared and/or paid by us for the ~~nine~~three months ended ~~September 30, 2021:~~March 31, 2022:

Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter.

Cash dividends of ~~$65.5~~$21.8 million were paid to holders of the Series A Preferred during the ~~nine~~three months ended ~~September 30, 2021.~~March 31, 2022. As of ~~September 30, 2021,~~March 31, 2022, cash dividends accrued for our Series A Preferred were $21.8 million, which were paid on May 2, 2022.

In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, which will be ~~paid on November 12, 2021.~~recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our Consolidated Financial Statements.

The following table details cash outlays for capital projects for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 and ~~2020:~~2021:

	Nine Months Ended September 30,						Three Months Ended March 31,
	2021			2020			2022		2021
	(In millions)						(In millions)
Capital expenditures:
Growth (1)	$	238.1		$	542.6		$	123.3	$	62.5
Maintenance (2)		78.4			67.7			39.2		20.9
Gross capital expenditures		316.5			610.3			162.5		83.4
Transfers from materials and supplies inventory to property, plant and equipment		(2.4	)		(1.9	)		—		(0.1	)
Change in capital project payables and accruals, net		7.5			194.7			41.9		12.9
Cash outlays for capital projects	$	321.6		$	803.1		$	204.4	$	96.2

The increase in total growth capital expenditures was primarily due to system expansions in the Permian in response to increasing activity levels. The increase in total maintenance capital expenditures was primarily due to our growing infrastructure footprint.

We currently estimate that in ~~2021~~2022 we will invest ~~approximately $350~~between $700 to ~~$450~~$800 million in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that ~~2021~~2022 maintenance capital expenditures, net of noncontrolling interests, will be approximately ~~$120~~$150 million.

Total growth capital expenditures were lower for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2020, including Trains 7 and 8, the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and additional processing plants and associated infrastructure in the Permian Basin. Total maintenance capital expenditures were higher for the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020, primarily due to timing of maintenance projects.

As of ~~September 30, 2021,~~March 31, 2022, there were ~~$65.7~~$67.6 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. All of our commodity derivatives are 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 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 ~~2025.~~2027. Market conditions may also impact our ability to enter into future commodity derivative contracts.

A 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, 2021,~~March 31, 2022, 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 Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. 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. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities 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 the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect,While we ~~expect to~~ have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges ~~at any time, even if~~so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where 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.~~prices. 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, NGL or crude oil 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, 2021:~~March 31, 2022:

										Fair Value			Result of 10% Price Decrease			Result of 10% Price Increase
	Fair Value			Result of 10% Price Decrease			Result of 10% Price Increase			(In millions)
Natural gas	$	(140.3	)	$	(93.7	)	$	(186.9	)	$	(333.3	)	$	(257.0	)	$	(409.6	)
NGLs		(334.8	)		(251.2	)		(418.4	)		(309.9	)		(222.0	)		(397.8	)
Crude oil		(52.3	)		(33.4	)		(71.2	)		(94.5	)		(65.8	)		(123.2	)
Total	$	(527.4	)	$	(378.3	)	$	(676.5	)	$	(737.7	)	$	(544.8	)	$	(930.6	)

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

~~Our operating revenues increased (decreased) by ($83.7) million and~~ $~~109.2~~ ~~million~~ ~~during~~During the three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020 and~~our operating revenues decreased by ($~~328.6)~~322.7) million and ~~$337.3~~($134.7) million ~~during the nine months ended September 30, 2021 and 2020,~~ as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of ($~~51.2)~~316.7) million at December 31, ~~2020~~2021 to a net liability position of ($~~527.4)~~737.7) million at ~~September 30, 2021.~~March 31, 2022. Forward commodity prices have moved unfavorably relative to the fixed prices on our derivative contracts, creating this net liability position.

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the ~~TRC Revolver, the TRP~~TRGP Revolver and the Securitization Facility. As of ~~September 30, 2021,~~March 31, 2022, 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 ~~TRC Revolver, the TRP~~TRGP Revolver and the Securitization Facility will also increase. As of ~~September 30, 2021, the Partnership~~March 31, 2022, we had ~~$340.0 million~~$1.3 billion in outstanding variable rate ~~borrowings under the Securitization Facility and we had no borrowings under the TRP Revolver and TRC Revolver.~~borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact ~~the Partnership’s and~~ our consolidated annual interest expense by ~~$3.4~~$12.7 million based on our ~~September 30, 2021~~March 31, 2022 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,~~entity. As of March 31, 2022, all of our commodity derivative instruments with the exception of our futures contracts were in a net liability position, and ~~would reduce our maximum loss due to counterparty credit~~as such, we had no counter-party risk ~~by $9.1 million~~exposure as of September 30, 2021. The range of losses attributable to our individual counterparties as of September 30, 2021 would be between $9.4 million and $10.8 million, depending on the counterparty in default.that date.

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, 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. Our allowance for doubtful accounts was ~~$3.6 million and~~ $0.1 million as of ~~September 30, 2021~~both March 31, 2022 and December 31, ~~2020.~~2021. Changes in the allowance for doubtful accounts were not material for the three ~~and nine~~ months ended ~~September 30, 2021.~~March 31, 2022.

~~No customer comprised 10% or greater of our consolidated revenues during the three and nine months ended September 30, 2021.~~ ~~No customer comprised 10% or greater of our consolidated revenues during~~During the three months ended ~~September 30, 2020. During the nine months ended September 30, 2020,~~March 31, 2022, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 10% of our consolidated revenues. No customer comprised 10% or greater of our consolidated revenues during the three months ended March 31, 2021.

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, 2021,~~March 31, 2022, 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.

On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 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.

In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings.

Additional information required for this item is provided in Note 1315 – 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 risk factor discussed below.~~Report. All of these risks and uncertainties ~~including those risks discussed below,~~ could adversely affect our business, financial condition and/or results of operations.

~~Weather may limit our ability to operate our business and could adversely affect our operating results.~~

The weather in the areas in which we operate can cause disruptions and in some cases suspension of our operations and development activities. Unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause a loss of throughput from temporary cessation of activities or lost or damaged equipment. For example, the recent winter storms in February 2021 adversely affected Targa’s operations and the operations and financial condition of some energy companies, including some of our counterparties. As a result of the winter storms, certain companies have declared force majeure under commercial agreements or have defaulted (or may default) on payment obligations. Our planning for normal climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects of such weather conditions in the future, and not all such effects can be predicted, eliminated or insured against. Some forecasters expect that potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have a material adverse effect on our operations. Any unusual or prolonged severe weather or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, or floods in our or our customers’ areas of operations or markets, whether due to climate change or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

~~Not applicable.~~On May 3, 2022, our board of directors adopted amended and restated bylaws, effective May 3, 2022 (the “Second Amended and Restated Bylaws”). The Second Amended and Restated Bylaws amended and restated our Amended and Restated Bylaws, as adopted and amended by our board of directors on December 10, 2010 (the “Amended and Restated Bylaws”) and amended by our board of directors on January 12, 2016 (the “First Amendment”). The Second Amended and Restated Bylaws (a) encompass the changes made to the Amended and Restated Bylaws pursuant to the First Amendment and (b) replace the threshold in the Amended and Restated Bylaws of an affirmative vote of the holders of at least 66.67 percent of the voting power for the removal for cause of any director with a threshold of the affirmative vote of the holders of a majority of the voting power.

The foregoing description of the Second Amended and Restated Bylaws is qualified in its entirety by reference to the full text of the Second Amended and Restated Bylaws, which is attached here as Exhibit 3.4 and incorporated herein by reference.

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		20-3701075
(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)

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021		4

Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~		5

Consolidated Statements of Comprehensive Income (Loss) for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~		6

Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the three ~~and nine~~ months ended ~~September 30,~~ March 31, 2022 and 2021 ~~and 2020~~		7

Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~		119

Notes to Consolidated Financial Statements		1210

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2826

Item 3. Quantitative and Qualitative Disclosures About Market Risk		4442

Item 4. Controls and Procedures		4745

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		4846

Item 1A. Risk Factors		4846

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4846

Item 3. Defaults Upon Senior Securities		4946

Item 4. Mine Safety Disclosures		4947

Item 5. Other Information		4947

Item 6. Exhibits		4947

SIGNATURES

Signatures		5150

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
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
gal		U.S. gallons
LIBOR		London Inter-Bank 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
SOFR		Secured Overnight Financing Rate
STACK		Sooner Trend, Anadarko, Canadian and Kingfisher

	September 30, 2021			December 31, 2020
Current:
Obligations of the Partnership: (1)
Accounts receivable securitization facility, due April 2022 (2)	$	340.0		$	350.0
TPL notes, 4¾% fixed rate, due November 2021 (3)		0			6.5
		340.0			356.5
Finance lease liabilities		12.6			12.1
Current debt obligations		352.6			368.6

Long-term:
TRC obligations:
TRC Senior secured revolving credit facility, variable rate, due June 2023 (4)		0			555.0
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due June 2023 (5)		0			280.0
Senior unsecured notes:
4¼% fixed rate, due November 2023 (6)		0			583.9
5⅛% fixed rate, due February 2025		0			481.0
5⅞% fixed rate, due April 2026		963.2			963.2
5⅜% fixed rate, due February 2027		468.1			468.1
6½% fixed rate, due July 2027		705.2			705.2
5% fixed rate, due January 2028		700.3			700.3
6⅞% fixed rate, due January 2029		679.3			679.3
5½% fixed rate, due March 2030		949.6			949.6
4⅞% fixed rate, due February 2031		1,000.0			1,000.0
4% fixed rate, due January 2032		1,000.0			0
TPL notes, 5⅞% fixed rate, due August 2023 (3)		0			48.1
Unamortized premium		0			0.2
		6,465.7			7,413.9
Debt issuance costs, net of amortization		(46.3	)		(45.5	)
Finance lease liabilities		14.7			18.7
Long-term debt		6,434.1			7,387.1
Total debt obligations	$	6,786.7		$	7,755.7
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRC Senior secured credit facility (4)	$	0		$	0
Letters of credit outstanding under the Partnership senior secured revolving credit facility (5)		48.8			44.4
	$	48.8		$	44.4

	March 31, 2022			December 31, 2021
Current:
Partnership accounts receivable securitization facility, due April 2022 (1)	$	270.0		$	150.0
Finance lease liabilities		13.8			12.8
Current debt obligations		283.8			162.8

Long-term:
TRGP senior revolving credit facility, variable rate, due February 2027 (2)		995.0			0
Senior unsecured notes issued by the Partnership: (3)
5.875% fixed rate, due April 2026 (4)		963.2			963.2
5.375% fixed rate, due February 2027 (5)		0			468.1
6.500% fixed rate, due July 2027		705.2			705.2
5.000% fixed rate, due January 2028		700.3			700.3
6.875% fixed rate, due January 2029		679.3			679.3
5.500% fixed rate, due March 2030		949.6			949.6
4.875% fixed rate, due February 2031		1,000.0			1,000.0
4.000% fixed rate, due January 2032		1,000.0			1,000.0
		6,992.6			6,465.7
Debt issuance costs, net of amortization		(41.3	)		(45.0	)
Finance lease liabilities		13.6			13.7
Long-term debt (6)		6,964.9			6,434.4
Total debt obligations	$	7,248.7		$	6,597.2
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRGP senior revolving credit facility (3)	$	58.7		$	0
Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)		0			71.3
	$	58.7		$	71.3


Title of each class	Trading Symbol(s)	Name of exchange on which registered
Common Stock	TRGP	New York Stock Exchange

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

	September 30, 2021
Balance at December 31, 2020	$	1,382.4
Amortization		(98.2	)
Balance at September 30, 2021	$	1,284.2

	March 31, 2022
Balance at December 31, 2021	$	1,094.8
Amortization		(28.0	)
Balance at March 31, 2022	$	1,066.8

	Balance at December 31, 2021		Equity Earnings (Loss)			Cash Distributions			Contributions		Balance at March 31, 2022
GCX (1)	$	421.0	$	5.7		$	(7.3	)	$	—	$	419.4
Little Missouri 4		98.1		0.3			(4.7	)		—		93.7
GCF (2)		28.8		(0.7	)		—			0.5		28.6
T2 Eagle Ford (3)		21.9		(0.6	)		(0.8	)		—		20.5
T2 LaSalle (3)		4.2		(0.2	)		—			—		4.0
Cayenne		12.5		1.1			—			—		13.6
Total	$	586.5	$	5.6		$	(12.8	)	$	0.5	$	579.8

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
~~TRC~~TRGP Revolver	~~1.9%~~1.5% - ~~1.9%~~1.8%	~~1.9%~~1.6%
~~TRP Revolver~~	~~1.6% - 1.9%~~	~~1.8%~~
~~Partnership's~~ Securitization Facility	1.1% - ~~1.8%~~1.2%	~~1.3%~~1.2%

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
September 30, 2021	November 15, 2021	$		23.3	$		22.9	$		0.4	$		0.10000
June 30, 2021	August 16, 2021			23.3			22.9			0.4			0.10000
March 31, 2021	May 14, 2021			23.3			22.9			0.4			0.10000
December 31, 2020	February 16, 2021			23.3			22.9			0.4			0.10000

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2021	November 11, 2021	$		45.6	$		45.6
June 30, 2021	August 12, 2021			45.5			45.5
March 31, 2021	May 12, 2021			47.0			47.0
December 31, 2020	February 11, 2021			54.3			47.6

		Fair Value as of September 30, 2021					Fair Value as of December 31, 2020
	Balance Sheet	Derivative		Derivative			Derivative		Derivative
	Location	Assets		Liabilities			Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	36.1	$	(464.3	)	$	24.2	$	(140.2	)
	Long-term		0.2		(148.3	)		5.1		(43.4	)
Total derivatives designated as hedging instruments		$	36.3	$	(612.6	)	$	29.3	$	(183.6	)
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	46.6	$	(8.0	)	$	61.3	$	(2.4	)
	Long-term		13.2		(2.9	)		44.2		0
Total derivatives not designated as hedging instruments		$	59.8	$	(10.9	)	$	105.5	$	(2.4	)
Total current position		$	82.7	$	(472.3	)	$	85.5	$	(142.6	)
Total long-term position			13.4		(151.2	)		49.3		(43.4	)
Total derivatives		$	96.1	$	(623.5	)	$	134.8	$	(186.0	)

		Fair Value as of March 31, 2022					Fair Value as of December 31, 2021
	Balance Sheet	Derivative		Derivative			Derivative		Derivative
	Location	Assets		Liabilities			Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	22.0	$	(447.8	)	$	25.5	$	(252.6	)
	Long-term		4.6		(126.7	)		6.2		(84.3	)
Total derivatives designated as hedging instruments		$	26.6	$	(574.5	)	$	31.7	$	(336.9	)
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0	$	(52.0	)	$	17.6	$	(5.6	)
	Long-term		2.7		(140.5	)		1.5		(25.0	)
Total derivatives not designated as hedging instruments		$	2.7	$	(192.5	)	$	19.1	$	(30.6	)
Total current position		$	22.0	$	(499.8	)	$	43.1	$	(258.2	)
Total long-term position			7.3		(267.2	)		7.7		(109.3	)
Total derivatives		$	29.3	$	(767.0	)	$	50.8	$	(367.5	)

	Commodity
	Derivative Contracts
	Asset (Liability)
Balance, December 31, 2020	$	(0.2	)
New Level 3 derivative instruments		0
Transfers out of Level 3 (1)		0.2
Unrealized gain (loss) included in OCI		(0.1	)
Balance, September 30, 2021	$	(0.1	)

			2021				2022				2023 and after
Fixed consideration to be recognized as of September 30, 2021			$	125.9			$	450.5			$	2,612.3

			2022				2023				2024 and after
Fixed consideration to be recognized as of March 31, 2022			$	346.9			$	398.5			$	2,319.0

	Three Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	135.7	$	1,616.5	$	88.6	$	—		$	1,840.8
Fees from midstream services		126.2		148.1		—		—			274.3
		261.9		1,764.6		88.6		—			2,115.1
Intersegment revenues
Sales of commodities		611.9		37.4		—		(649.3	)		—
Fees from midstream services		1.7		8.5		—		(10.2	)		—
		613.6		45.9		—		(659.5	)		—
Revenues	$	875.5	$	1,810.5	$	88.6	$	(659.5	)	$	2,115.1
Operating margin (1)	$	261.0	$	280.4	$	88.6	$	—		$	630.0
Other financial information:
Total assets (2)	$	8,929.4	$	6,841.2	$	78.2	$	203.3		$	16,052.1
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	63.6	$	69.0	$	—	$	4.0		$	136.6

	Gathering and Processing		Logistics and Transportation		Other			Total
	(In millions)
Three Months Ended:
September 30, 2021	$	361.4	$	280.7	$	13.5		$	655.6
September 30, 2020		261.0		280.4		88.6			630.0

Nine Months Ended:
September 30, 2021	$	938.2	$	920.5	$	(55.6	)	$	1,803.1
September 30, 2020		753.7		806.0		215.9			1,775.6

	October 29, 2021
	TRC		TRP			Consolidated Total
	(In millions)
Cash on hand (1)	$	26.4	$	280.7		$	307.1
Total availability under the TRC Revolver		670.0		—			670.0
Total availability under the TRP Revolver		—		2,200.0			2,200.0
Total availability under the Partnership's Securitization Facility		—		400.0			400.0
		696.4		2,880.7			3,577.1

Less: Outstanding borrowings under the TRC Revolver		—		—			—
Outstanding borrowings under the TRP Revolver		—		—			—
Outstanding borrowings under the Partnership's Securitization Facility		—		(400.0	)		(400.0	)
Outstanding letters of credit under the TRP Revolver		—		(48.8	)		(48.8	)
Total liquidity	$	696.4	$	2,431.9		$	3,128.3

Summarized Combined Balance Sheet Information
	March 31, 2022			December 31, 2021
	(In millions)
ASSETS
Current assets	$	773.1		$	832.9
Current assets - affiliates		10.4			24.4
Long-term assets		6,226.8			6,253.9
Long-term assets - affiliates		10.5			10.5
Total assets	$	7,020.8		$	7,121.7

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities	$	2,069.2		$	1,525.6
Current liabilities - affiliates		218.2			195.8
Long-term liabilities		7,471.3			6,875.5
Series A Preferred		749.7			749.7
Targa Resources Corp. stockholders' equity		(3,487.6	)		(2,224.9	)
Total liabilities and owners' equity	$	7,020.8		$	7,121.7

Summarized Combined Statement of Operations Information
	Three Months Ended			Year Ended
	March 31, 2022			December 31, 2021
	(In millions)
Revenues	$	5,040.7		$	16,900.5
Operating income (loss)		(66.4	)		5.7
Net loss		(157.9	)		(371.0	)
Dividends on Series A Preferred		21.8			87.3

Period	Total number of shares purchased (1)		Average price per share		Total number of shares purchased as part of publicly announced plans (2)		Maximum approximate dollar value of shares that may yet be purchased under the plan (in thousands) (2)
July 1, 2021 - July 31, 2021		273	$	42.11		—	$	408,499.4
August 1, 2021 - August 31, 2021		107,719	$	42.13		—	$	408,499.4
September 1, 2021 - September 30, 2021		—	$	—		—	$	408,499.4

Number		Description

3.1		Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).

3.2		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 26, 2021 (File No. 001-34991)).

3.3		Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State of the State of Delaware on March 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).

~~3.4~~3.4*		Second Amended and Restated Bylaws of Targa Resources Corp. ~~(incorporated by reference to Exhibit 3.2 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).~~

~~3.5~~		First Amendment to the Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed January 15, 2016 (File No. 001-34991)).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).

10.1*4.2		Parent Guarantee dated as of February 18, 2022, by and among Targa Resources Corp. and certain of its subsidiaries (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 23, 2022 (File No. 001-34991)).

4.3		Indenture, dated as of April 6, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report on Form 8-K filed April 6, 2022 (File No. 001-34991)).

4.4		First Supplemental Indenture, dated as of April 6, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Current Report on Form 8-K filed April 6, 2022 (File No. 001-34991)).

4.5		Form of Notes (included in Exhibit 4.4 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K filed April 6, 2022 (File No. 001-34991)).

10.1		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 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.~~Association (incorporated by reference to Exhibit 10.32 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.2*10.2		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 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.~~Association (incorporated by reference to Exhibit 10.43 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.3*Number		Description
10.3		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 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.~~Association (incorporated by reference to Exhibit 10.52 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.4*10.4		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 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 (incorporated by reference to Exhibit 10.61 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

~~Number~~		~~Description~~

10.5*10.5		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 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.~~Association (incorporated by reference to Exhibit 10.68 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.6*10.6		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 to Indenture dated August 18, 2020 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association.~~Association (incorporated by reference to Exhibit 10.74 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.7*10.7		Supplemental Indenture dated ~~September 17, 2021~~January 28, 2022 to Indenture dated February 2, 2021 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National ~~Association.~~Association (incorporated by reference to Exhibit 10.80 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.8+		Form of Performance Share Unit Grant Agreement, dated as of January 20, 2022 under Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).

10.9		Credit Agreement dated as of February 17, 2022, by and among Targa Resources Corp., Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 23, 2022 (File No. 001-34991)).

10.10		Twelfth Amendment to Receivables Purchase Agreement, dated April 19, 2022, 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 Corp.’s Current Report on Form 8-K filed April 22, 2022 (File No. 001-34991)).

22.1*		List of Subsidiary Guarantors.

31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*		Inline XBRL Taxonomy Extension Schema Document

101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.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

Number		Description
104*		The cover page from this Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2021,~~March 31,2022, formatted in Inline XBRL (included with Exhibit 101 attachments).

	Targa Resources Corp.
	(Registrant)

Date: ~~November 4, 2021~~May 5, 2022	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)