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 ~~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 ~~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,~~28, 2022, there were ~~228,971,730~~226,375,387 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~~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			September 30, 2022			December 31, 2021
		(Unaudited)						(Unaudited)
		(In millions)						(In millions)
ASSETS	ASSETS							ASSETS
Current assets:
Cash and cash equivalents		$	228.6		$	242.8		$	192.9		$	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 $2.2 million and $0.1 million at September 30, 2022 and December 31, 2021									1,534.9			1,331.9
Inventories			316.8			181.5			471.3			153.4
Assets from risk management activities			82.7			85.5			185.8			43.1
Other current assets			74.2			87.7			112.4			82.9
Total current assets			1,993.3			1,460.3			2,497.3			1,769.8
Property, plant and equipment, net			11,922.4			12,173.6			13,716.4			11,667.7
Intangible assets, net			1,284.2			1,382.4			2,839.7			1,094.8
Long-term assets from risk management activities			13.4			49.3			50.2			7.7
Investments in unconsolidated affiliates			674.6			714.0			136.4			586.5
Other long-term assets			84.8			96.1			149.9			81.7
Total assets		$	15,972.7		$	15,875.7		$	19,389.9		$	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		$	1,806.4		$	1,402.3
Accrued liabilities			240.2			186.4			293.7			272.2
Distributions payable			71.0			115.4			25.2			64.5
Interest payable			79.9			132.6			100.9			138.5
Liabilities from risk management activities			472.3			142.6			401.0			258.2
Current debt obligations			352.6			368.6			766.5			162.8
Total current liabilities			2,868.3			1,779.4			3,393.7			2,298.5
Long-term debt			6,434.1			7,387.1			10,431.3			6,434.4
Long-term liabilities from risk management activities			151.2			43.4			165.1			109.3
Deferred income taxes, net			78.7			152.1			301.4			136.0
Other long-term liabilities			290.8			309.1			367.0			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 14)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero and 919,300 shares issued and outstanding as of September 30, 2022 and December 31, 2021), net of discount (see Note 9)									—			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 September 30, 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
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
September 30, 2022 237,684,682 226,257,924
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, zero shares issued and outstanding)									—			—
Additional paid-in capital			4,299.7			4,839.9			3,767.8			4,268.9
Retained earnings (deficit)			(1,508.7	)		(1,893.5	)		(944.8	)		(1,822.3	)
Accumulated other comprehensive income (loss)			(442.1	)		(141.8	)		(6.7	)		(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 (11,426,758 shares as of September 30, 2022 and 7,884,171 shares as of December 31, 2021)									(432.0	)		(204.1	)
Total Targa Resources Corp. stockholders' equity			2,185.1			2,653.9			2,384.5			2,011.8
Noncontrolling interests			3,214.8			3,249.3			2,346.9			3,166.9
Total owners' equity			5,399.9			5,903.2			4,731.4			5,178.7
Total liabilities, Series A Preferred Stock and owners' equity		$	15,972.7		$	15,875.7		$	19,389.9		$	15,208.2


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020			2022			2021			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		$	4,800.3		$	4,118.1		$	14,990.7		$	10,577.3
Fees from midstream services		341.6			274.3			930.9			786.7			559.8			341.6			1,384.3			930.9
Total revenues		4,459.7			2,115.1			11,508.2			5,687.5			5,360.1			4,459.7			16,375.0			11,508.2
Costs and expenses:
Product purchases and fuel		3,614.7			1,322.9			9,159.8			3,405.1			4,306.3			3,614.7			13,557.8			9,159.8
Operating expenses		189.4			162.2			545.3			506.8			261.3			189.4			660.6			545.3
Depreciation and amortization expense		222.8			203.7			650.9			647.3			287.2			222.8			766.2			650.9
General and administrative expense		67.3			58.6			192.4			180.6			79.1			67.3			217.2			192.4
Impairment of long-lived assets		—			—			—			2,442.8
Other operating (income) expense		(1.0	)		72.2			3.4			73.8			(3.8	)		(1.0	)		(4.4	)		3.4
Income (loss) from operations		366.5			295.5			956.4			(1,568.9	)		430.0			366.5			1,177.6			956.4
Other income (expense):
Interest expense, net		(91.0	)		(97.7	)		(284.2	)		(292.4	)		(125.8	)		(91.0	)		(300.5	)		(284.2	)
Equity earnings (loss)		14.3			18.6			38.9			54.1			1.7			14.3			8.7			38.9
Gain (loss) from financing activities		—			(13.7	)		(16.6	)		47.4			—			—			(49.6	)		(16.6	)
Gain (loss) from sale of equity method investment														—			—			435.9			—
Other, net		0.2			1.4			0.3			2.2			(14.6	)		0.2			(14.6	)		0.3
Income (loss) before income taxes		290.0			204.1			694.8			(1,757.6	)		291.3			290.0			1,257.5			694.8
Income tax (expense) benefit		(2.0	)		(31.9	)		(23.5	)		286.6			(12.0	)		(2.0	)		(122.0	)		(23.5	)
Net income (loss)		288.0			172.2			671.3			(1,471.0	)		279.3			288.0			1,135.5			671.3
Less: Net income (loss) attributable to noncontrolling interests		105.8			102.9			286.5			116.5			86.2			105.8			258.0			286.5
Net income (loss) attributable to Targa Resources Corp.		182.2			69.3			384.8			(1,587.5	)		193.1			182.2			877.5			384.8
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			30.0			65.5
Deemed dividends on Series A Preferred Stock		—			9.5			—			27.7			—			—			215.5			—
Net income (loss) attributable to common shareholders	$	160.4		$	36.9		$	319.3		$	(1,684.0	)	$	193.1		$	160.4		$	578.9		$	319.3

Net income (loss) per common share - basic	$	0.70		$	0.16		$	1.40		$	(7.22	)	$	0.85		$	0.70		$	2.54		$	1.40
Net income (loss) per common share - diluted	$	0.66		$	0.16		$	1.38		$	(7.22	)	$	0.84		$	0.66		$	2.50		$	1.38
Weighted average shares outstanding - basic		228.8			233.4			228.6			233.2			226.6			228.8			227.6			228.6
Weighted average shares outstanding - diluted		276.4			233.8			231.6			233.2			230.3			276.4			231.5			231.6


	Three Months Ended September 30,																	Three Months Ended September 30,
	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								$	279.3								$	288.0
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	(294.7	)	$	71.2			(223.5	)	$	(128.7	)	$	31.7		(97.0	)	$	225.4		$	(50.4	)		175.0		$	(294.7	)	$	71.2			(223.5	)
Settlements reclassified to revenues		100.4			(24.6	)		75.8			(19.2	)		3.8		(15.4	)		121.7			(27.0	)		94.7			100.4			(24.6	)		75.8
Other comprehensive income (loss)		(194.3	)		46.6			(147.7	)		(147.9	)		35.5		(112.4	)		347.1			(77.4	)		269.7			(194.3	)		46.6			(147.7	)
Comprehensive income (loss)								140.3								59.8									549.0									140.3
Less: Comprehensive income (loss) attributable to noncontrolling interests								105.8								102.9									86.2									105.8
Comprehensive income (loss) attributable to Targa Resources Corp.							$	34.5							$	(43.1	)							$	462.8								$	34.5

	Nine Months Ended September 30,																	Nine Months Ended September 30,
	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)							$	671.3							$	(1,471.0	)							$	1,135.5								$	671.3
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	(698.9	)	$	167.1			(531.8	)	$	(102.6	)	$	23.5		(79.1	)	$	(136.7	)	$	30.5			(106.2	)	$	(698.9	)	$	167.1			(531.8	)
Settlements reclassified to revenues		303.8			(72.3	)		231.5			(139.4	)		35.2		(104.2	)		425.2			(94.8	)		330.4			303.8			(72.3	)		231.5
Other comprehensive income (loss)		(395.1	)		94.8			(300.3	)		(242.0	)		58.7		(183.3	)		288.5			(64.3	)		224.2			(395.1	)		94.8			(300.3	)
Comprehensive income (loss)								371.0								(1,654.3	)								1,359.7									371.0
Less: Comprehensive income (loss) attributable to noncontrolling interests								286.5								116.5									258.0									286.5
Comprehensive income (loss) attributable to Targa Resources Corp.							$	84.5							$	(1,770.8	)							$	1,101.7								$	84.5

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, 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

Compensation on equity grants

—

—

14.7

—

—

—

—

—

14.7

—

Distribution equivalent rights

—

—

(1.1
)

—

—

—

—

—

(1.1
)

—

Shares issued under compensation program

416

—

—

—

—

—

—

—

—

—

Shares and units tendered for tax withholding obligations

(108
)

—

—

—

—

108

(4.5
)

—

(4.5
)

—

Series A Preferred Stock dividends

Dividends - $23.75 per share

—

—

—

(21.8
)

—

—

—

—

(21.8
)

—

Dividends in excess of retained earnings

—

—

(21.8
)

21.8

—

—

—

—

—

—

Common stock dividends

Dividends - $0.10 per share

—

—

—

(22.9
)

—

—

—

—

(22.9
)

—

Dividends in excess of retained earnings

—

—

(22.9
)

22.9

—

—

—

—

—

—

Distributions to noncontrolling interests

—

—

—

—

—

—

—

(110.4
)

(110.4
)

—

Contributions from noncontrolling interests

—

—

—

—

—

—

—

9.1

9.1

—

Other comprehensive income (loss)

—

—

—

—

(147.7
)

—

—

—

(147.7
)

—

Net income (loss)

—

—

—

182.2

—

—

—

105.8

288.0

—

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
						Additional			Earnings			Other			Treasury								Total			Series A										Retained			Accumulated
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred							Additional			Earnings			Other			Treasury								Total			Series A
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock		Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	(Unaudited)																											Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(In millions, except shares in thousands)																											(Unaudited)
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
																												(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
Compensation on equity grants		—			—		16.4			—			—			—		—			—			16.4			—		—			—		14.7			—			—			—		—			—			14.7			—
Distribution equivalent rights		—			—		1.9			—			—			—		—			—			1.9			—		—			—		(1.1	)		—			—			—		—			—			(1.1	)		—
Shares issued under compensation program		453			—		—			—			—			—		—			—			—			—		416			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(112	)		—		—			—			—			112		(2.1	)		—			(2.1	)		—
Shares tendered for tax withholding obligations																													(108	)		—		—			—			—			108		(4.5	)		—			(4.5	)		—
Series A Preferred Stock dividends
Dividends - $23.75 per share		—			—		—			(22.9	)		—			—		—			—			(22.9	)		—
Dividends - $23.75 per share																													—			—		—			(21.8	)		—			—		—			—			(21.8	)		—
Dividends in excess of retained earnings		—			—		(22.9	)		22.9			—			—		—			—			—			—		—			—		(21.8	)		21.8			—			—		—			—			—			—
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 - $0.10 per share																													—			—		—			(22.9	)		—			—		—			—			(22.9	)		—
Dividends in excess of retained earnings		—			—		(23.3	)		23.3			—			—		—			—			—			—		—			—		(22.9	)		22.9			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(113.1	)		(113.1	)		—		—			—		—			—			—			—		—			(110.4	)		(110.4	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			7.7			7.7			—		—			—		—			—			—			—		—			9.1			9.1			—
Non-cash allocation to noncontrolling interests		—			—		—			—			—			—		—			27.5			27.5			—
Other comprehensive income (loss)		—			—		—			—			(112.4	)		—		—			—			(112.4	)		—		—			—		—			—			(147.7	)		—		—			—			(147.7	)		—
Net income (loss)		—			—		—			69.3			—			—		—			102.9			172.2			—		—			—		—			182.2			—			—		—			105.8			288.0			—
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, 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
						Additional			Earnings			Other			Treasury								Total			Series A										Retained			Accumulated
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred							Additional			Earnings			Other			Treasury								Total			Series A
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock		Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	(Unaudited)																											Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(In millions, except shares in thousands)																											(Unaudited)
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
																												(In millions, except shares in thousands)
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		—			—		44.6			—			—			—		—			—			44.6			—		—			—		41.8			—			—			—		—			—			41.8			—
Distribution equivalent rights		—			—		(2.4	)		—			—			—		—			—			(2.4	)		—		—			—		(5.2	)		—			—			—		—			—			(5.2	)		—
Shares issued under compensation program		1,294			—		—			—			—			—		—			—			—			—		1,580			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(393	)		—		—			—			—			393		(13.1	)		—			(13.1	)		—
Shares tendered for tax withholding obligations																													(526	)		—		—			—			—			526		(31.1	)		—			(31.1	)		—
Repurchases of common stock																													(3,017	)		—		—			—			—			3,017		(196.8	)		—			(196.8	)		—
Series A Preferred Stock dividends
Dividends - $71.25 per share		—			—		—			(65.5	)		—			—		—			—			(65.5	)		—
Dividends - $47.50 per share																													—			—		—			(30.0	)		—			—		—			—			(30.0	)		—
Dividends in excess of retained earnings		—			—		(65.5	)		65.5			—			—		—			—			—			—		—			—		(30.0	)		30.0			—			—		—			—			—			—
Deemed dividends - redemption of Series A Preferred Stock																													—			—		(215.5	)		—			—			—		—			—			(215.5	)		—
Common stock dividends
Dividends - $0.30 per share		—			—		—			(68.6	)		—			—		—			—			(68.6	)		—
Dividends - $1.05 per share																													—			—		—			(239.1	)		—			—		—			—			(239.1	)		—
Dividends in excess of retained earnings		—			—		(68.6	)		68.6			—			—		—			—			—			—		—			—		(239.1	)		239.1			—			—		—			—			—			—
Redemption of Series A Preferred Stock																													—			—		—			—			—			—		—			—			—			(749.7	)
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(334.2	)		(334.2	)		—		—			—		—			—			—			—		—			(234.0	)		(234.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			13.2			13.2			—		—			—		—			—			—			—		—			13.9			13.9			—
Repurchase of noncontrolling interests, net of tax																													—			—		(53.1	)		—			—			—		—			(857.9	)		(911.0	)		—
Other comprehensive income (loss)		—			—		—			—			(300.3	)		—		—			—			(300.3	)		—		—			—		—			—			224.2			—		—			—			224.2			—
Net income (loss)		—			—		—			384.8			—			—		—			286.5			671.3			—		—			—		—			877.5			—			—		—			258.0			1,135.5			—
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, September 30, 2022																													226,258		$	0.2	$	3,767.8		$	(944.8	)	$	(6.7	)		11,427	$	(432.0	)	$	2,346.9		$	4,731.4		$	—

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

									Retained			Accumulated
						Additional			Earnings			Other			Treasury									Total			Series A										Retained			Accumulated
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owner's			Preferred							Additional			Earnings			Other			Treasury								Total			Series A
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity			Stock		Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	(Unaudited)																												Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(In millions, except shares in thousands)																												(Unaudited)
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
																													(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																														—			—		(448.3	)		—			—			—		—			—			(448.3	)		448.3
Compensation on equity grants		—			—		49.5			—			—			—			—			—			49.5			—		—			—		44.6			—			—			—		—			—			44.6			—
Distribution equivalent rights		—			—		(3.5	)		—			—			—			—			—			(3.5	)		—		—			—		(2.4	)		—			—			—		—			—			(2.4	)		—
Shares issued under compensation program		892			—		—			—			—			—			—			—			—			—		1,294			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(218	)		—		—			—			—			218			(5.5	)		—			(5.5	)		—
Shares tendered for tax withholding obligations																														(393	)		—		—			—			—			393		(13.1	)		—			(13.1	)		—
Series A Preferred Stock dividends
Dividends - $71.25 per share		—			—		—			(68.8	)		—			—			—			—			(68.8	)		—
Dividends - $71.25 per share																														—			—		—			(65.5	)		—			—		—			—			(65.5	)		—
Dividends in excess of retained earnings		—			—		(68.8	)		68.8			—			—			—			—			—			—		—			—		(65.5	)		65.5			—			—		—			—			—			—
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 - $0.30 per share																														—			—		—			(68.6	)		—			—		—			—			(68.6	)		—
Dividends in excess of retained earnings		—			—		(259.0	)		259.0			—			—			—			—			—			—		—			—		(68.6	)		68.6			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—			—			(322.9	)		(322.9	)		—		—			—		—			—			—			—		—			(334.2	)		(334.2	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—			—			33.3			33.3			—		—			—		—			—			—			—		—			13.2			13.2			—
Non-cash allocation to noncontrolling interests		—			—		—			—			—			—			—			27.5			27.5			—
Other comprehensive income (loss)		—			—		—			—			(183.3	)		—			—			—			(183.3	)		—		—			—		—			—			(300.3	)		—		—			—			(300.3	)		—
Net income (loss)		—			—		—			(1,587.5	)		—			—			—			116.5			(1,471.0	)		—		—			—		—			384.8			—			—		—			286.5			671.3			—
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, 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


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2022			2021
	(Unaudited)						(Unaudited)
	(In millions)						(In millions)
Cash flows from operating activities
Net income (loss)	$	671.3		$	(1,471.0	)	$	1,135.5		$	671.3
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		7.8			8.5			7.2			7.8
Compensation on equity grants		44.6			49.5			41.8			44.6
Depreciation and amortization expense		650.9			647.3			766.2			650.9
Impairment of long-lived assets		—			2,442.8
(Gain) loss on sale or disposition of assets								(8.1	)		(1.7	)
Write-downs of assets								3.7			5.0
Accretion of asset retirement obligations		3.0			2.6			3.5			3.0
Deferred income tax expense (benefit)		21.5			(269.8	)		116.4			21.5
Equity (earnings) loss of unconsolidated affiliates		(38.9	)		(54.1	)		(8.7	)		(38.9	)
Distributions of earnings received from unconsolidated affiliates		64.5			65.5			11.0			64.5
Risk management activities		55.6			(214.2	)		295.0			55.6
(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	)		49.6			16.6
Changes in operating assets and liabilities:
(Gain) loss from sale of equity method investment								(435.9	)		—
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets		(359.8	)		168.7			79.4			(359.8	)
Inventories		(128.0	)		(115.8	)		(320.5	)		(128.0	)
Accounts payable, accrued liabilities and other liabilities		839.1			(158.0	)		144.8			839.1
Interest payable		(52.7	)		(30.4	)		(37.6	)		(52.7	)
Net cash provided by operating activities		1,798.8			1,095.7			1,843.3			1,798.8
Cash flows from investing activities
Outlays for property, plant and equipment		(321.6	)		(803.1	)		(815.4	)		(321.6	)
Proceeds from sale of business and assets		7.9			135.9
Outlays for business acquisition, net of cash acquired								(3,514.8	)		—
Outlays for asset acquisition, net of cash acquired								(203.7	)		—
Proceeds from sale of assets								18.3			7.9
Investments in unconsolidated affiliates		(0.6	)		(2.2	)		(1.5	)		(0.6	)
Proceeds from sale of equity method investment								857.0			—
Return of capital from unconsolidated affiliates		14.5			10.7			12.5			14.5
Other, net		0.2			4.7			—			0.2
Net cash used in investing activities		(299.6	)		(654.0	)
Net cash provided by (used in) investing activities								(3,647.6	)		(299.6	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		620.0			1,460.0			5,305.0			620.0
Repayments of credit facilities		(1,455.0	)		(1,360.0	)		(4,755.0	)		(1,455.0	)
Proceeds from borrowings of commercial paper notes								8,584.8			—
Repayments of commercial paper notes								(7,952.8	)		—
Proceeds from borrowings under term loan facility								1,500.0			—
Proceeds from borrowings under accounts receivable securitization facility		570.0			476.4			1,180.0			570.0
Repayments of accounts receivable securitization facility		(580.0	)		(596.4	)		(580.0	)		(580.0	)
Proceeds from issuance of senior notes		1,000.0			1,000.0			2,741.4			1,000.0
Redemption of senior notes		(1,132.0	)		(831.0	)		(1,473.2	)		(1,132.0	)
Principal payments of finance leases		(9.4	)		(9.3	)		(10.8	)		(9.4	)
Costs incurred in connection with financing arrangements		(9.6	)		(9.6	)		(44.4	)		(9.6	)
Repurchase of shares and units under compensation plans		(13.1	)		(5.5	)
Repurchase of shares								(227.9	)		(13.1	)
Contributions from noncontrolling interests		13.2			33.3			13.9			13.2
Distributions to noncontrolling interests		(377.3	)		(310.6	)		(252.0	)		(377.3	)
Distributions to Partnership unitholders		—			(8.4	)
Repurchase of noncontrolling interests								(926.3	)		—
Redemption of Series A Preferred Stock								(965.2	)		—
Dividends paid to common and Series A Preferred shareholders		(140.2	)		(336.7	)		(298.8	)		(140.2	)
Net cash provided by (used in) financing activities		(1,513.4	)		(497.8	)		1,838.7			(1,513.4	)
Net change in cash and cash equivalents		(14.2	)		(56.1	)		34.4			(14.2	)
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		$	192.9		$	228.6

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

Note 1 — Organization and Operations

Our Organization

Targa Resources 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~~consolidated the Partnership and its subsidiaries under ~~GAAP. Our~~GAAP, and prepared accompanying consolidated financial statements ~~do not differ materially~~under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of ~~TRP.~~the Partnership. The most noteworthy differences are:

•

the inclusion of the TRGP senior revolving credit facility and term loan facility;

•

the inclusion of the TRGP senior notes;

•

the inclusion of the TRGP commercial paper notes;

•

the inclusion of Series A Preferred Stock (“Series A Preferred”); and

•

the impacts of TRGP’s treatment as a corporation for U.S. federal income tax purposes.

•

the inclusion of the TRC revolving credit facility (while we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership);

•

~~the inclusion of Series A Preferred Stock (“Series A Preferred”); and~~

•

~~the impacts of TRC’s treatment as a corporation for U.S. federal income tax purposes.~~

Our Operations

The Company is primarily engaged in the business of:

•

gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;

•

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

•

gathering, storing, terminaling, and purchasing and selling crude oil.

•

~~gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;~~

•

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

•

~~gathering, storing, terminaling, and purchasing and selling crude oil.~~

See Note 1718 – Segment Information for certain financial information regarding our business segments.

Note 2 — Basis of Presentation

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, of a normal recurring nature and considered 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~~2022 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2021.~~2022.

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 were no significant updates or revisions to our accounting policies during the nine months ended September 30, ~~2021.~~2022.

~~Recent Accounting Pronouncements~~

Recently ~~adopted~~issued accounting pronouncements not yet adopted

~~Convertible Debt and Equity Instruments~~Supplier Finance Programs

In ~~August 2020,~~September 2022, the Financial Accounting Standards Board ~~(“FASB”~~("FASB") issued Accounting Standards Update ~~(“ASU”~~("ASU") ~~2020-06,~~ 2022-04, ~~Debt - Debt with Conversion~~Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual and ~~Other Options (Subtopic 470-20)~~interim disclosure of the key terms of outstanding supplier finance programs and ~~Derivatives~~a rollforward of the related obligations. These amendments do not affect the recognition, measurement or financial statement presentation of the supplier finance program obligations. These amendments are effective for fiscal years beginning after December 15, 2022, except for the rollforward requirements, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. We are currently evaluating the effect of these amendments on our consolidated financial statements.

Recently Adopted Accounting Pronouncements

Revenue Contract Assets and ~~Hedging - Contracts~~Liabilities Acquired in ~~Entity’s Own Equity (Subtopic 815-40)~~a Business Combination

In October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for ~~Convertible Instruments~~Contract Assets and Contract Liabilities from Contracts with Customers. Amendments in ~~an Entity’s Own Equity.~~ ~~The amendments in~~this update ~~simplify the accounting for convertible debt instruments~~require application of Accounting Standards Codification 606, Revenue from Contracts with Customers ("ASC 606") to recognize and ~~convertible preferred stock by reducing the number of accounting models~~measure contract assets and ~~embedded conversion features that can be recognized separately~~contract liabilities from ~~the primary contract. These amendments also enhance transparency and improve disclosures for convertible instruments and earnings per share guidance.~~contracts with customers acquired in a business combination. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, ~~2021,~~2022, with early adoption permitted. ~~This update permits~~However, an entity that elects to early adopt must apply the ~~use of either~~amendments to all business combinations that occurred during the ~~modified retrospective or full retrospective method of adoption.~~

~~On a modified retrospective basis, we~~fiscal year that includes the interim period. We early adopted the amendments ~~early, effective~~on April 1, 2022 and have applied them to business combinations in 2022 and thereafter. We applied the amendments to the Delaware Basin Acquisition, as defined in Note 4 – Joint Ventures, Acquisitions and Divestitures, by recognizing contract liabilities from contracts with customers in accordance with ASC 606.

Note 4 – Joint Ventures, Acquisitions and Divestitures

DevCo Joint Ventures

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix 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.

Acquisitions

South Texas Acquisition

In April 2022, we completed the acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9 million (the “South Texas Acquisition”), subject to customary closing adjustments. We expect to make a final closing adjustment payment of approximately $1.5 million in the fourth quarter of 2022. 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 two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and have been prospectively consolidated beginning in the second quarter of 2022. We accounted for the purchase as an asset acquisition and have capitalized $1.8 million of acquisition-related costs and assumed liabilities of $1.8 million as components of the cost of assets acquired. We allocated $28.1 million to our purchase of Southcross’ interest in the two operated joint ventures for purposes of consolidation and $169.7 million, $3.9 million and $5.3 million of the residual cost to property, plant and equipment, current assets and liabilities, net and other non-current assets, respectively.

Delaware Basin Acquisition

On July 29, 2022, we completed the acquisition of all of the interests in Lucid Energy Delaware, LLC (“Lucid”) from Riverstone Holdings LLC and Goldman Sachs Asset Management for approximately $3.5 billion in cash (the “Delaware Basin Acquisition”), subject to customary closing adjustments. We funded the acquisition with (i) $1.5 billion in proceeds drawn under our Term Loan Agreement with Mizuho Bank, Ltd. (“Mizuho”) as the Administrative Agent and a lender, and other lenders party thereto (the “Term Loan Facility”), (ii) $750.0 million in aggregate principal amount of our 5.200% Senior Notes due 2027 (the “5.200% Notes”) and $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the “6.250% Notes”) pursuant to an underwritten public offering that closed in July 2022 and (iii) $800.0 million drawn on our $2.75 billion TRGP revolving credit facility (the “TRGP Revolver”). We recorded $16.9 million of debt issuance costs related to the Term Loan Facility, the 5.200% Notes and the 6.250% Notes in our Consolidated Balance Sheets. See Note 7 – Debt Obligations for further details on our financing activities.

The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing services in the Delaware Basin, through owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets increase our footprint in the Delaware Basin and are integrated into our Permian Delaware operations.

The Delaware Basin Acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The preliminary allocation of the purchase price, which is subject to certain adjustments, was based upon preliminary valuations from estimates and assumptions that management believes are reasonable; however, management’s estimates and assumptions are subject to change upon the completion of the final valuations or as information necessary to complete the fair value analysis is obtained. The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other cash flows, market-participant assumptions (e.g., discount rate and exit multiple), expectations regarding customer contracts and relationships, tangible asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 13 – Fair Value Measurements. These inputs require judgments and estimates at the time of valuation. We are in the process of finalizing valuations related to property, plant and equipment and identifiable intangible assets. The final valuation will be completed no later than one year from the acquisition date.

The following table summarizes the preliminary fair values assigned to assets acquired and liabilities assumed (in millions):


Cash and cash equivalents	$	9.9
Trade receivables, net of allowances (1)		210.2
Other current assets		6.5
Property, plant and equipment, net		1,678.8
Intangible assets, net		1,881.6
Other long-term assets		57.3
Current liabilities		(237.3	)
Other long-term liabilities		(100.8	)
Purchase price	$	3,506.2

(1)

The fair value of the assets acquired includes trade receivables of $210.2 million. The gross amount due under contract was $212.9 million, of which $2.7 million was expected to be uncollectible. Trade receivables, net of allowances, excludes $18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the purchase price in accordance with ASC 805.

The preliminary value of property, plant and equipment is determined using the cost approach and is primarily comprised of Gathering and Processing assets that will be depreciated on a straight-line basis over an estimated weighted-average useful life of 20 years. The associated useful lives of property, plant and equipment were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

The preliminary value of intangible assets is comprised of customer relationships, which represent estimated value of long-term contracts with customers, that will be amortized in a manner that closely resembles the expected benefit pattern of the intangible assets over an estimated useful life of 14 years. The associated useful lives of intangible assets were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

The results of operations attributable to the assets and liabilities acquired in the Delaware Basin Acquisition have been included in our consolidated financial statements as part of our Permian Delaware operations in our Gathering and Processing segment since the date of the acquisition. Revenue and Net Income attributable to the assets acquired for the period August 1, 2022 through September 30, 2022 were $104.0 million and $4.7 million, respectively. As of September 30, 2022, we had incurred $14.3 million of acquisition-related costs.

Unaudited Pro Forma Financial Information

The following unaudited pro forma summary presents the consolidated results of operations for the three and nine months ended September 30, 2022 and 2021 as if the Delaware Basin Acquisition had occurred on January 1, 2021. The ~~primary effect~~unaudited pro forma financial information is presented for informational purposes only and is not necessarily indicative of our results of operations that would have occurred had the transaction been consummated at the beginning of the ~~adoption on~~period presented, nor is it necessarily indicative of future results.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Revenues	$	5,391.1	$	4,595.2	$	16,604.0	$	11,869.4
Net income (loss)		288.2		242.4		1,087.9		514.9

The summarized unaudited pro forma information has been calculated after applying our accounting policies and reflects adjustments for 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 featurefollowing:

•

Reflects depreciation 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~~amortization based on the ~~initial relative~~preliminary fair ~~value allocation~~values of property, plant and equipment and intangible assets, respectively. Property, plant and equipment are depreciated utilizing a straight-line approach. Intangible assets are amortized in a manner that closely resembles their expected benefit pattern;

•

Excludes $14.3 million of acquisition-related costs incurred as of September 30, 2022 from pro forma net ~~proceeds~~income for the three and nine months ended September 30, 2022. Pro forma net income for the three and nine months ended September 30, 2021 was adjusted to include those costs;

•

Excludes the impact of ~~$787.1 million, less~~operations previously sold by Lucid, prior to Targa’s acquisition of Lucid;

•

Excludes the ~~carrying value~~impact of historical activity between Targa and Lucid, prior to Targa’s acquisition of Lucid;

•

Excludes general and administrative expense related to Lucid’s former parent company, which Targa did not acquire;

•

Excludes amortization of interest expense and debt issuance costs associated with Lucid’s debt, which was not assumed by Targa;

•

Includes interest expense and debt issuance cost amortization associated with Targa’s borrowings to finance the Delaware Basin Acquisition; and

•

Reflects the income tax effects of the ~~portion repurchased in December 2020. The adoption did not have an impact on retained earnings (deficit), but rather,~~above pro forma adjustments.

Divestitures

In May 2022, we completed 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 attributablesale of Targa GCX Pipeline LLC to ~~the beneficial conversion feature and therefore, accretion~~a third party for $857.0 million (the “GCX Sale”). As a result of the ~~discount as~~GCX Sale, we recognized a ~~deemed dividend is no longer required. The other aspects~~gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in the ~~ASU did not have a material effect~~second quarter of 2022.

See Note 6 – Investments in Unconsolidated Affiliates for further discussion on ~~our consolidated financial statements.~~South Texas Acquisition and GCX Sale.

Note 45 — Property, Plant and Equipment and Intangible Assets


	September 30, 2021			December 31, 2020			Estimated Useful Lives (In Years)	September 30, 2022			December 31, 2021			Estimated Useful Lives (In Years)
Gathering systems	$	9,279.7		$	9,216.1		5 to 20	$	10,432.4		$	9,318.2		5 to 20
Processing and fractionation facilities		6,365.1			6,276.8		5 to 25		7,425.4			6,388.8		5 to 25
Terminaling and storage facilities		1,313.5			1,555.1		5 to 25		1,342.1			1,313.8		5 to 25
Transportation assets		2,628.4			2,567.7		10 to 50		2,791.6			2,671.0		10 to 50
Other property, plant and equipment		355.3			32.4		3 to 50		357.1			340.9		3 to 50
Land		160.8			160.8		—		162.7			160.8		—
Construction in progress		263.1			324.3		—		657.4			347.0		—
Finance lease right-of-use assets		55.2			51.8				90.5			55.6		5 to 14
Property, plant and equipment		20,421.1			20,185.0				23,259.2			20,596.1
Accumulated depreciation, amortization and impairment		(8,498.7	)		(8,011.4	)			(9,542.8	)		(8,928.4	)
Property, plant and equipment, net	$	11,922.4		$	12,173.6			$	13,716.4		$	11,667.7

Intangible assets		2,643.5			2,643.5		10 to 20		4,379.3			2,642.9		10 to 20
Accumulated amortization and impairment		(1,359.3	)		(1,261.1	)			(1,539.6	)		(1,548.1	)
Intangible assets, net	$	1,284.2		$	1,382.4			$	2,839.7		$	1,094.8

During the three and nine months ended September 30, 2022, depreciation expense was $206.5 million and $629.5 million, respectively. During the three and nine months ended September 30, 2021, depreciation expense was ~~$190.2~~$190.2 million and ~~$552.7~~$552.7 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 There were no 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~~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 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 ofended September 30, 2022 and 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 relationships acquired in the Delaware Basin Acquisition, and customer contracts and customer relationships acquired in prior business combinations. The fair ~~value~~values 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~~$243.8 million, ~~$122.7~~$388.4 million, ~~$117.5~~$376.3 million, ~~$113.7~~$334.1 million and ~~$110.6~~$283.9 million for each of the years ~~2021~~2022 through ~~2025,~~2026, respectively.

The changes in our intangible assets are as follows:


	September 30, 2022
Balance at December 31, 2021	$	1,094.8
Additions from Delaware Basin Acquisition		1,881.6
Amortization		(136.7	)
Balance at September 30, 2022	$	2,839.7

Note 6 – Investments in Unconsolidated Affiliates

As of September 30, 2022, our investments in unconsolidated affiliates consist of the following:

Gathering and Processing Segment

•

a 50% operated ownership interest in Little Missouri 4 LLC (“Little Missouri 4”).

Logistics and Transportation Segment

•

a 38.8% operated ownership interest in Gulf Coast Fractionators (“GCF”); and

•

a 50% operated ownership interest in Cayenne Pipeline LLC (“Cayenne”).

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.

In April 2022, we completed the South Texas Acquisition for $201.9 million, subject to customary closing adjustments. We expect to make a final closing adjustment payment of approximately $1.5 million in the fourth quarter of 2022. Prior to closing the South Texas Acquisition, we had two operated joint ventures in South Texas: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford” and, together with T2 Lasalle, the “T2 Joint Ventures”). Following the closing of the South Texas Acquisition, we own 100% of the interest in the T2 Joint Ventures.

In May 2022, we completed the GCX Sale for $857.0 million. Prior to the GCX Sale, we owned a 25% non-operated ownership interest in GCX. Following the announcement of the GCX Sale in February 2022, we ceased recognizing equity earnings (loss) due to the terms of the sales agreement. As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in the second quarter of 2022.

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

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


	Balance at December 31, 2021		Equity Earnings (Loss)			Cash Distributions			Disposition/ Consolidation			Contributions		Balance at September 30, 2022
GCX	$	421.0	$	5.7		$	(14.3	)	$	(412.4	)	$	—	$	—
Little Missouri 4		98.1		4.3			(7.4	)		—			—		95.0
GCF (1)		28.8		(2.4	)		—			—			1.5		27.9
T2 Eagle Ford (2)		21.9		(0.6	)		(0.8	)		(20.5	)		—		—
T2 LaSalle (2)		4.2		(0.3	)		—			(3.9	)		—		—
Cayenne		12.5		2.0			(1.0	)		—			—		13.5
Total	$	586.5	$	8.7		$	(23.5	)	$	(436.8	)	$	1.5	$	136.4

(1)

Targa assumed operatorship of GCF in the first half of 2021.

(2)

Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100% owned and consolidated by Targa.

Note 7 — Debt Obligations

September 30, 2021

Balance at December 31, 2020

$
1,382.4

Amortization

(98.2
)
Balance at September 30, 2021

$
1,284.2


	September 30, 2022			December 31, 2021
Current:
Partnership accounts receivable securitization facility, due September 2023 (1)	$	750.0		$	150.0
Finance lease liabilities		16.5			12.8
Current debt obligations		766.5			162.8

Long-term:
Term loan facility, variable rate, due July 2025		1,500.0			—
TRGP senior revolving credit facility, variable rate, due February 2027 (2)		1,182.0			—
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027		750.0			—
4.200% fixed rate, due February 2033		750.0			—
4.950% fixed rate, due April 2052		750.0			—
6.250% fixed rate, due July 2052		500.0			—
Unamortized discount		(8.5	)		—
Senior unsecured notes issued by the Partnership: (3)
5.875% fixed rate, due April 2026 (4)		—			963.2
5.375% fixed rate, due February 2027 (5)		—			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
		10,457.9			6,465.7
Debt issuance costs, net of amortization		(66.5	)		(45.0	)
Finance lease liabilities		39.9			13.7
Long-term debt		10,431.3			6,434.4
Total debt obligations	$	11,197.8		$	6,597.2
Irrevocable standby letters of credit: (2)
Letters of credit outstanding under the TRGP senior revolving credit facility	$	47.2		$	—
Letters of credit outstanding under the Partnership senior secured revolving credit facility		—			71.3
	$	47.2		$	71.3

(1)

In September 2022, the Partnership amended the Securitization Facility to, among other things, increase the facility size from $400.0 million to $800.0 million and extend the facility termination date to September 1, 2023. As of September 30, 2022, the Partnership had $750.0 million of qualifying receivables under its $800.0 million accounts receivable securitization facility (the “Securitization Facility”), resulting in $50.0 million of availability.

(2)

In February 2022, we entered into the TRGP Revolver which matures in February 2027, and 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”). In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program. As of September 30, 2022, the TRGP Revolver had $550.0 million borrowings outstanding and the Commercial Paper Program had $632.0 million borrowings outstanding, resulting in approximately $1.5 billion of available liquidity, after accounting for outstanding letters of credit. As of December 31, 2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver.

(3)

As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes.

(4)

In April 2022, the Partnership redeemed all of the outstanding 5.875% Senior Notes due 2026 (the “5.875% Notes”).

(5)

In March 2022, the Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) with the available liquidity under the TRGP Revolver.

~~Note 5 — Debt Obligations~~

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

~~(1)~~

~~While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.~~

~~(2)~~

As of September 30, 2021, the Partnership had $340.0 million of qualifying receivables under its $400.0 million accounts receivable securitization facility (“Securitization Facility”), resulting in $60.0 million availability. During the second quarter of 2021, the Partnership amended the Securitization Facility to increase the facility size from $350.0 million to $400.0 million to more closely align with our expectation for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.

~~(3)~~

~~“TPL” refers to Targa Pipeline Partners LP.~~

~~(4)~~

~~As of September 30, 2021, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $670.0 million.~~

~~(5)~~

~~As of September 30, 2021, availability under the Partnership’s $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,151.2 million.~~

~~(6)~~

~~On May 17, 2021, the Partnership redeemed all of the remaining outstanding~~ ~~4¼%~~ ~~Senior Notes due 2023.~~

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, ~~2021:~~2022:


		Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
~~TRC~~TRGP Revolver	and Commercial Paper Program	~~1.9%~~	1.5% - ~~1.9%~~4.7%		~~1.9%~~	2.9%
~~TRP Revolver~~	Securitization Facility	~~1.6%~~	1.1% - ~~1.9%~~3.8%		~~1.8%~~	2.0%
~~Partnership's Securitization~~Term Loan Facility		~~1.1%~~	4.1% - ~~1.8%~~4.1%		~~1.3%~~	4.1%

Compliance with Debt Covenants

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

~~Senior Unsecured Notes Issuance and Redemptions~~

In February ~~2021,~~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 ~~issued $1.0~~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 September 30, 2022, $5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

Debt Obligations

Partnership’s Accounts Receivable Securitization Facility

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. In September 2022, the Partnership amended the Securitization Facility to, among other things, increase the facility size from $400.0 million to $800.0 million and extend the facility termination date to September 1, 2023.

TRGP Revolver

In February 2022, we entered into the 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 million comprised of $12.5 million of premiums paid and~~$0.8 million.

Term Loan Facility

In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a ~~write-off of $2.4 million of debt issuance costs.~~

~~Additionally, TPL redeemed all~~three-year, $1.5 billion unsecured term loan facility. The Term Loan Facility matures in July 2025. We used the proceeds from the Term Loan Facility to fund a portion of the Delaware Basin Acquisition.

The Term Loan Facility bears interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which is the highest of the (i) federal funds rate plus 0.5%, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75% dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding ~~TPL~~ at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR plus 4¾0.10% ~~Senior Notes due 2021 and TPL~~ plus an applicable margin ranging from 5⅞1.125% ~~Senior Notes due 2023 (collectively,~~to 1.75% dependent on the ~~“TPL Notes”) on February 22, 2021 with available liquidity~~Debt Rating.

Our obligations under the ~~TRP Revolver. As a result~~Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the ~~redemptions~~Company, including the Partnership.

The Term Loan Facility requires the Company to maintain a Consolidated Leverage Ratio (as defined in the Term Loan Facility), determined as of the ~~TPL~~last day of each quarter for the four-fiscal-quarter-period ending on the date of determination, of no more than 5.50 to 1.00. For any four-fiscal-quarter-period during which a material acquisition or disposition occurs, the total leverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal-quarter-period.

The Term Loan Facility limits the Company’s ability to make dividends to stockholders if an event of default (as defined in the Term Loan Facility) exists or would result from such distribution. In addition, the Term Loan Facility contains various covenants that may limit, among other things, the Company’s ability to incur subsidiary indebtedness, grant liens, make investments, merge or consolidate, and engage in transactions with affiliates.

Commercial Paper Program

In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. The commercial paper notes are presented in Long-term debt on our Consolidated Balance Sheets.

Senior Unsecured Notes ~~we recorded a gain due to debt extinguishment of $0.2 million.~~Redemptions and Issuances

~~The~~In March 2022, the Partnership redeemed all of the outstanding 4¼5.375% ~~Senior~~ Notes ~~due 2023 (the “4¼~~at a redemption price equal to $1,026.88 for each $1,000 principal amount of 5.375% ~~Senior Notes”) on May 17, 2021~~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 ~~TRP~~TRGP Revolver. As a result of the redemption of the 4¼5.375% ~~Senior~~ Notes, we recorded a loss due to debt extinguishment of ~~$1.9 million.~~$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 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 $1.5 billion. 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. 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 was 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 of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.

In July 2022, we completed an underwritten public offering of the 5.200% Notes and the 6.250% Notes, resulting in net proceeds of approximately $1.2 billion. The 5.200% Notes and the 6.250% 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. The 5.200% Notes and the 6.250% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Third Supplemental Indenture, dated as of July 7, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.

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. 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~~.material.

Shelf Registration

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.

Contractual Obligations

The following table summarizes payment obligations as of September 30, 2022, for debt instruments after giving effect to the debt extinguishments detailed above:


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

Long-term debt obligations (1)	$	10,466.4	$	—	$	1,500.0	$	2,637.2	$	6,329.2
Interest on debt obligations (2)		4,870.7		524.6		1,049.3		882.0		2,414.8
	$	15,337.1	$	524.6	$	2,549.3	$	3,519.2	$	8,744.0

Payments Due By Period

Less Than

More Than

Total

1 Year

1-3 Years

3-5 Years

5 Years

Long-term debt obligations (1)

$
6,465.7

$
—

$
—

$
963.2

$
5,502.5

Interest on debt obligations (2)

2,547.3

359.4

707.3

674.6

806.0

$
9,013.0

$
359.4

$
707.3

$
1,637.8

$
6,308.5

(1)

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

(2)

Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing September 30, 2022 rates for floating debt. During the preparation of the Company's third quarter 2022 consolidated financial statements, the Company identified an error related to the disclosure of future payment obligations for interest on debt. The Company does not believe this disclosure error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements disclosures. As of March 31, 2022, the future payment obligations for interest on debt were $2,340.3 million in total, comprised of $347.2 million, $694.4 million, $637.5 million, and $661.2 million, for the periods less than 1 year, 1-3 years, 3-5 years, and more than 5 years, respectively. As of June 30, 2022, the future payment obligations for interest on debt were $3,496.8 million in total, comprised of $359.5 million, $719.0 million, $711.0 million, and $1,707.3 million, for the periods less than 1 year, 1-3 years, 3-5 years, and more than 5 years, respectively.

~~(1)~~

~~Represents scheduled future maturities of consolidated debt obligations for the periods indicated.~~

Other long-term liabilities are comprised of ~~deferred revenue, asset retirement obligations and operating lease liabilities.~~the following:


	September 30, 2022		December 31, 2021
Deferred revenue	$	197.1	$	171.8
Asset retirement obligations		96.7		72.1
Operating lease liabilities		59.7		34.5
Other liabilities		13.5		23.2
Total long-term liabilities	$	367.0	$	301.6

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~~2022 and December 31, ~~2020,~~2021, was ~~$165.8~~$197.1 million and ~~$168.5~~$171.8 million, respectively, which includes ~~$129.0~~$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.~~Note 14 – Contingencies.

~~As of September 30, 2021, we have accrued cumulative preferred dividends of $21.8 million on our~~ Series A Preferred Redemption

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 ~~will be~~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 ~~on November 12, 2021.~~of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Our Series A Preferred bore a cumulative 9.5% fixed dividend payable at the end of each fiscal quarter. During the ~~three and~~ nine months ended September 30, ~~2021,~~2022, we paid ~~$21.8 million and $65.5~~$51.8 million of dividends to preferred ~~shareholders, respectively.~~

~~We may redeem all or a portion of our~~shareholders. Following the redemption, we have no Series A Preferred inoutstanding and all rights of the ~~future pursuant to its terms or repurchase~~holders of shares of Series A Preferred shares in privately negotiated transactions. Such redemptions or repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.were terminated.

Note 810 — Common Stock and Related Matters

Shelf Registration

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

Common Stock Dividends

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.

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


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, 2022	November 15, 2022	$		80.5	$		79.2	$		1.3	$		0.35000
June 30, 2022	August 15, 2022			80.7			79.3			1.4			0.35000
March 31, 2022	May 16, 2022			81.2			79.8			1.4			0.35000
December 31, 2021	February 15, 2022			81.4			80.1			1.3			0.35000

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

(1)

Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

~~(1)~~

~~Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.~~

~~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 months ended September 30, 2021:~~

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 months ended September 30, 2021, we made a total of $46.0 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,
	2022		2021		2022		2021
	(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.	$	193.1	$	182.2	$	877.5	$	384.8
Less: Premium on repurchase of noncontrolling interests, net of tax		—		—		53.1		—
Less: Dividends on Series A Preferred (1)		—		21.8		30.0		65.5
Less: Deemed dividends on Series A Preferred (1)		—		—		215.5		—
Net income (loss) attributable to common shareholders for basic earnings per share	$	193.1	$	160.4	$	578.9	$	319.3

Weighted average shares outstanding - basic		226.6		228.8		227.6		228.6
Dilutive effect of unvested stock awards		3.7		3.3		3.9		3.0
Dilutive effect of Series A Preferred (1)		—		44.3		—		—
Weighted average shares outstanding - diluted		230.3		276.4		231.5		231.6

Net income (loss) available per common share - basic	$	0.85	$	0.70	$	2.54	$	1.40
Net income (loss) available per common share - diluted	$	0.84	$	0.66	$	2.50	$	1.38

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021

2020

(In millions, except per share amounts)

Net income (loss) attributable to Targa Resources Corp.

$
182.2

$
69.3

$
384.8

$
(1,587.5
)
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

Net income (loss) attributable to common shareholders for basic earnings per share

$
160.4

$
36.9

$
319.3

$
(1,684.0
)

Weighted average shares outstanding - basic

228.8

233.4

228.6

233.2

Dilutive effect of unvested stock awards

3.3

0.4

3.0

—

Dilutive effect of Series A Preferred Stock (1)

44.3

—

—

—

Weighted average shares outstanding - diluted

276.4

233.8

231.6

233.2

Net income (loss) available per common share - basic

$
0.70

$
0.16

$
1.40

$
(7.22
)
Net income (loss) available per common share - diluted

$
0.66

$
0.16

$
1.38

$
(7.22
)

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):

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,~~2022, the notional volumes of our commodity derivative contracts were:

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements.

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


		Fair Value as of September 30, 2021					Fair Value as of December 31, 2020						Fair Value as of September 30, 2022					Fair Value as of December 31, 2021
	Balance Sheet	Derivative		Derivative			Derivative		Derivative			Balance Sheet	Derivative		Derivative			Derivative		Derivative
	Location	Assets		Liabilities			Assets		Liabilities			Location	Assets		Liabilities			Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	36.1	$	(464.3	)	$	24.2	$	(140.2	)	Current	$	174.8	$	(171.0	)	$	25.5	$	(252.6	)
	Long-term		0.2		(148.3	)		5.1		(43.4	)	Long-term		47.4		(74.8	)		6.2		(84.3	)
Total derivatives designated as hedging instruments		$	36.3	$	(612.6	)	$	29.3	$	(183.6	)		$	222.2	$	(245.8	)	$	31.7	$	(336.9	)
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	46.6	$	(8.0	)	$	61.3	$	(2.4	)	Current	$	11.0	$	(230.0	)	$	17.6	$	(5.6	)
	Long-term		13.2		(2.9	)		44.2		0		Long-term		2.8		(90.3	)		1.5		(25.0	)
Total derivatives not designated as hedging instruments		$	59.8	$	(10.9	)	$	105.5	$	(2.4	)		$	13.8	$	(320.3	)	$	19.1	$	(30.6	)
Total current position		$	82.7	$	(472.3	)	$	85.5	$	(142.6	)		$	185.8	$	(401.0	)	$	43.1	$	(258.2	)
Total long-term position			13.4		(151.2	)		49.3		(43.4	)			50.2		(165.1	)		7.7		(109.3	)
Total derivatives		$	96.1	$	(623.5	)	$	134.8	$	(186.0	)		$	236.0	$	(566.1	)	$	50.8	$	(367.5	)

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
September 30, 2021		Asset		Liability			Collateral		Asset		Liability
															Gross Presentation								Pro Forma Net Presentation
September 30, 2022														September 30, 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	$	171.0	$	(401.0	)	$	(26.7	)	$	13.7	$	(270.4	)
	Counterparties without offsetting positions - assets		6.8		—			—		6.8		—		Counterparties without offsetting positions - assets		14.8		—			—			14.8		—
	Counterparties without offsetting positions - liabilities		—		(134.1	)		—		—		(134.1	)	Counterparties without offsetting positions - liabilities		—		—			—			—		—
			82.7		(472.3	)		27.0		17.7		(380.3	)			185.8		(401.0	)		(26.7	)		28.5		(270.4	)
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		43.8		(165.1	)		14.0			16.2		(123.5	)
	Counterparties without offsetting positions - assets		—		—			—		—		—		Counterparties without offsetting positions - assets		6.4		—			—			6.4		—
	Counterparties without offsetting positions - liabilities		—		(44.3	)		—		—		(44.3	)	Counterparties without offsetting positions - liabilities		—		—			—			—		—
			13.4		(151.2	)		—		3.4		(141.2	)			50.2		(165.1	)		14.0			22.6		(123.5	)
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		214.8		(566.1	)		(12.7	)		29.9		(393.9	)
	Counterparties without offsetting positions - assets		6.8		—			—		6.8		—		Counterparties without offsetting positions - assets		21.2		—			—			21.2		—
	Counterparties without offsetting positions - liabilities		—		(178.4	)		—		—		(178.4	)	Counterparties without offsetting positions - liabilities		—		—			—			—		—
		$	96.1	$	(623.5	)	$	27.0	$	21.1	$	(521.5	)		$	236.0	$	(566.1	)	$	(12.7	)	$	51.1	$	(393.9	)

		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. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured. As of September 30, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of ($392.3) 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 September 30, 2022, we would be required to post $77.4 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)~~330.1) million as of September 30, ~~2021.~~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)

Derivatives in Cash Flow

Three Months Ended September 30,

Nine Months Ended September 30,

Hedging Relationships

2021

2020

2021

2020

Commodity contracts

$
(294.7
)

$
(128.7
)

$
(698.9
)

$
(102.6
)


	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended September 30,					Nine Months Ended September 30,
Hedging Relationships	2022		2021			2022			2021
Commodity contracts	$	225.4	$	(294.7	)	$	(136.7	)	$	(698.9	)


	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended September 30,						Nine Months Ended September 30,
Location of Gain (Loss)	2022			2021			2022			2021
Revenues	$	(121.7	)	$	(100.4	)	$	(425.2	)	$	(303.8	)

Gain (Loss) Reclassified from OCI into
Income (Effective Portion)

Three Months Ended September 30,

Nine Months Ended September 30,

Location of Gain (Loss)

2021

2020

2021

2020

Revenues

$
(100.4
)

$
19.2

$
(303.8
)

$
139.4

Based on valuations as of September 30, ~~2021,~~2022, we expect to reclassify commodity hedge-related deferred losses of ($~~581.7)~~15.5) million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with ~~($433.7)~~$11.8 million of ~~losses~~gains to be reclassified over the next twelve months.

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

For the three ~~months ended 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~~and nine months ended September 30, ~~2021,~~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
Derivatives Not Designated	Recognized in Income on	Three Months Ended September 30,					Nine Months Ended September 30,
as Hedging Instruments	Derivatives	2022			2021		2022			2021
Commodity contracts	Revenue	$	(121.5	)	$	16.7	$	(317.5	)	$	(24.8	)

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,

as Hedging Instruments

Derivatives

2021

2020

2021

2020

Commodity contracts

Revenue

$
16.7

$
90.0

$
(24.8
)

$
197.9

See Note 1213 – Fair Value Measurements and Note 1718 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Note 1213 — Fair Value Measurements

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

Fair Value of Derivative Financial Instruments

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

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, ~~2021,~~2022, a net liability position of ($~~527.4)~~330.1) million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of ($~~676.5)~~556.2) 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)~~103.8) million.

Fair Value of Other Financial Instruments

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

•

the TRGP Revolver, commercial paper notes, Securitization Facility and Term Loan Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

•

the TRGP senior unsecured notes and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.

•

~~The~~ ~~TRC~~ ~~Revolver, TRP Revolver, and the Partnership’s Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and~~

•

~~The Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.~~

Fair Value Hierarchy

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

•

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

•

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

•

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

•

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

•

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

•

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

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


	September 30, 2022
	Carrying		Fair Value
	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)	$	230.5	$	230.5	$	—	$	230.5	$	—
Liabilities from commodity derivative contracts (1)		560.6		560.6		—		560.6		—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		192.9		192.9		—		—		—
TRGP Revolver and Commercial Paper Program		1,182.0		1,182.0		—		1,182.0		—
TRGP Senior unsecured notes		2,741.5		2,386.8		—		2,386.8		—
Term Loan Facility		1,500.0		1,500.0		—		1,500.0		—
Partnership's Senior unsecured notes		5,034.4		4,564.4		—		4,564.4		—
Securitization Facility		750.0		750.0		—		750.0		—


	December 31, 2021
	Carrying		Fair Value
	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)	$	46.6	$	46.6	$	—	$	46.6	$	—
Liabilities from commodity derivative contracts (1)		363.3		363.3		—		363.3		—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		158.5		158.5		—		—		—
Partnership's Senior unsecured notes		6,465.7		6,924.5		—		6,924.5		—
Securitization Facility		150.0		150.0		—		150.0		—

September 30, 2021

Carrying

Fair Value

Value

Total

Level 1

Level 2

Level 3

Financial Instruments Recorded on Our
Consolidated Balance Sheets at Fair Value:

Assets from commodity derivative contracts

$
96.1

$
96.1

$
0

$
96.1

$
0

Liabilities from commodity derivative contracts

623.5

623.5

0

623.4

0.1

Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:

Cash and cash equivalents

228.6

228.6

0

0

0

TRC Revolver

0

0

0

0

0

TRP Revolver

0

0

0

0

0

Partnership's Senior unsecured notes

6,465.7

6,909.8

0

6,909.8

0

Partnership's Securitization Facility

340.0

340.0

0

340.0

0

(1)

The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 12 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

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

We ~~reported~~report 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, 2022 and December 31, 2021, we had 1no 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:~~

~~(1)~~

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

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~~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.

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 appealed the award to 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. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to ~~litigation matters.~~losses or demurrage on crude oil. We are in the process of preparing our further appeal to the Supreme Court of Texas. The cumulative amount of interest on the award through September 30, 2022, if accrued, would have been approximately $39.6 million.

Note 1415 — Revenue

Fixed consideration allocated to remaining performance obligations

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 ~~18 years.~~17 years.

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 September 30, 2022	$	117.7	$	432.6	$	2,573.6

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 1718 – Segment Information.

Note 1516 — Income Taxes

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,~~2022, our valuation allowance was ~~$105.4~~$99.1 million, a decrease of ~~$88.8~~$111.5 million from December 31, ~~2020.~~2021. After the change in valuation allowance, we have a net deferred tax liability of ~~$78.7~~$301.4 million.

As we ~~begin achieving~~achieve 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 Internal Revenue Service (“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 have responded to information requests from the IRS and do not anticipate material changes in prior year taxable income.

On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for the 2019 and 2020 tax years. We are responding to the information requests from the IRS on these audits. The Company is not aware of any potential audit findings that would give rise to adjustments to taxable income and does not anticipate material changes related to these audits.

Note 1617 — Supplemental Cash Flow Information


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2022			2021
Cash:
Interest paid, net of capitalized interest (1)	$	327.8		$	315.9		$	332.6		$	327.8
Income taxes (received) paid, net		1.2			(44.4	)		1.1			1.2
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		(7.5	)		(194.7	)	$	(40.1	)	$	(7.5	)
Transfers from materials and supplies inventory to property, plant and equipment		2.4			1.9			—			2.4
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests		(43.1	)		3.9		$	(18.0	)	$	(43.1	)

(1)

Interest capitalized on major projects was $9.5 million and $2.7 million for the nine months ended September 30, 2022 and 2021.

~~(1)~~

~~Interest capitalized on major projects was $2.7 million and $31.1 million for the nine months ended September 30, 2021 and 2020.~~

We operate in 2two 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.

Reportable segment information is shown in the following tables:


	Three Months Ended September 30, 2022
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	180.7	$	4,731.8	$	(112.2	)	$	—		$	4,800.3
Fees from midstream services		382.0		177.8		—			—			559.8
		562.7		4,909.6		(112.2	)		—			5,360.1
Intersegment revenues
Sales of commodities		2,768.2		160.7		—			(2,928.9	)		—
Fees from midstream services		0.3		11.6		—			(11.9	)		—
		2,768.5		172.3		—			(2,940.8	)		—
Revenues	$	3,331.2	$	5,081.9	$	(112.2	)	$	(2,940.8	)	$	5,360.1
Operating margin (1)	$	564.6	$	340.2	$	(112.2	)
Other financial information:
Total assets (2)	$	12,126.3	$	7,067.6	$	1.5		$	194.5		$	19,389.9
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	222.0	$	139.1	$	—		$	8.0		$	369.1

Three Months Ended September 30, 2021

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

Fees from midstream services

205.3

136.3

—

—

341.6

361.5

4,084.7

13.5

—

4,459.7

Intersegment revenues

Sales of commodities

1,786.0

108.3

—

(1,894.3
)

—

Fees from midstream services

0.6

11.5

—

(12.1
)

—

1,786.6

119.8

—

(1,906.4
)

—

Revenues

$
2,148.1

$
4,204.5

$
13.5

$
(1,906.4
)

$
4,459.7

Operating margin (1)

$
361.4

$
280.7

$
13.5

$
—

$
655.6

Other financial information:

Total assets (2)

$
8,560.6

$
7,180.5

$
42.3

$
189.3

$
15,972.7

Goodwill

$
45.2

$
—

$
—

$
—

$
45.2

Capital expenditures

$
98.0

$
16.8

$
—

$
2.7

$
117.5

(1)

Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

(2)

Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.


	Three Months Ended September 30, 2021
	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
Fees from midstream services		205.3		136.3		—		—			341.6
		361.5		4,084.7		13.5		—			4,459.7
Intersegment revenues
Sales of commodities		1,786.0		108.3		—		(1,894.3	)		—
Fees from midstream services		0.6		11.5		—		(12.1	)		—
		1,786.6		119.8		—		(1,906.4	)		—
Revenues	$	2,148.1	$	4,204.5	$	13.5	$	(1,906.4	)	$	4,459.7
Operating margin (1)	$	361.4	$	280.7	$	13.5
Other financial information:
Total assets (2)	$	8,560.6	$	7,180.5	$	42.3	$	189.3		$	15,972.7
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	98.0	$	16.8	$	—	$	2.7		$	117.5

(1)

Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

(2)

Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.


	Nine Months Ended September 30, 2022
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	577.0	$	14,708.6	$	(294.9	)	$	—		$	14,990.7
Fees from midstream services		844.2		540.1		—			—			1,384.3
		1,421.2		15,248.7		(294.9	)		—			16,375.0
Intersegment revenues
Sales of commodities		7,455.4		416.5		—			(7,871.9	)		—
Fees from midstream services		0.1		34.3		—			(34.4	)		—
		7,455.5		450.8		—			(7,906.3	)		—
Revenues	$	8,876.7	$	15,699.5	$	(294.9	)	$	(7,906.3	)	$	16,375.0
Operating margin (1)	$	1,437.0	$	1,014.6	$	(294.9	)
Other financial information:
Total assets (2)	$	12,126.3	$	7,067.6	$	1.5		$	194.5		$	19,389.9
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	551.7	$	206.9	$	—		$	16.7		$	775.3

(1)

Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

(2)

Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.


	Nine Months Ended September 30, 2021
	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
Fees from midstream services		496.7		434.2		—			—			930.9
		942.9		10,620.9		(55.6	)		—			11,508.2
Intersegment revenues
Sales of commodities		3,940.4		283.5		—			(4,223.9	)		—
Fees from midstream services		2.8		27.0		—			(29.8	)		—
		3,943.2		310.5		—			(4,253.7	)		—
Revenues	$	4,886.1	$	10,931.4	$	(55.6	)	$	(4,253.7	)	$	11,508.2
Operating margin (1)	$	938.2	$	920.5	$	(55.6	)
Other financial information:
Total assets (2)	$	8,560.6	$	7,180.5	$	42.3		$	189.3		$	15,972.7
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	265.4	$	42.0	$	—		$	9.1		$	316.5

(1)

Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

(2)

Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

~~(1)~~

~~Operating margin is calculated by subtracting Product purchases and fuel from Revenues.~~

~~(2)~~

~~Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.~~

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

~~(1)~~

~~Operating margin is calculated by subtracting Product purchases and fuel from Revenues.~~

~~(2)~~

~~Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.~~

Nine Months Ended September 30, 2021

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

Fees from midstream services

496.7

434.2

—

—

930.9

942.9

10,620.9

(55.6
)

—

11,508.2

Intersegment revenues

Sales of commodities

3,940.4

283.5

—

(4,223.9
)

—

Fees from midstream services

2.8

27.0

—

(29.8
)

—

3,943.2

310.5

—

(4,253.7
)

—

Revenues

$
4,886.1

$
10,931.4

$
(55.6
)

$
(4,253.7
)

$
11,508.2

Operating margin (1)

$
938.2

$
920.5

$
(55.6
)

$
—

$
1,803.1

Other financial information:

Total assets (2)

$
8,560.6

$
7,180.5

$
42.3

$
189.3

$
15,972.7

Goodwill

$
45.2

$
—

$
—

$
—

$
45.2

Capital expenditures

$
265.4

$
42.0

$
—

$
9.1

$
316.5

~~(1)~~

~~Operating margin is calculated by subtracting Product purchases and fuel from Revenues.~~

~~(2)~~

~~Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.~~

Nine Months Ended September 30, 2020

Gathering and Processing

Logistics and Transportation

Other

Corporate
and
Eliminations

Total

Revenues

Sales of commodities

$
512.9

$
4,172.0

$
215.9

$
—

$
4,900.8

Fees from midstream services

354.5

432.2

—

—

786.7

867.4

4,604.2

215.9

—

5,687.5

Intersegment revenues

Sales of commodities

1,444.3

140.1

—

(1,584.4
)

—

Fees from midstream services

4.9

23.8

—

(28.7
)

—

1,449.2

163.9

—

(1,613.1
)

—

Revenues

$
2,316.6

$
4,768.1

$
215.9

$
(1,613.1
)

$
5,687.5

Operating margin (1)

$
753.7

$
806.0

$
215.9

$
—

$
1,775.6

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

$
218.0

$
375.5

$
—

$
16.8

$
610.3

~~(1)~~

~~Operating margin is calculated by subtracting Product purchases and fuel from Revenues.~~

~~(2)~~

~~Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.~~

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,
	2022			2021			2022			2021
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	1,748.1		$	916.1		$	4,244.1		$	2,371.3
NGL		3,145.4			3,185.0			11,048.3			8,278.4
Condensate and crude oil		150.0			100.7			441.0			256.2
		5,043.5			4,201.8			15,733.4			10,905.9
Non-customer revenue:
Derivative activities - Hedge		(121.7	)		(100.4	)		(425.2	)		(303.8	)
Derivative activities - Non-hedge (1)		(121.5	)		16.7			(317.5	)		(24.8	)
		(243.2	)		(83.7	)		(742.7	)		(328.6	)
Total sales of commodities		4,800.3			4,118.1			14,990.7			10,577.3

Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		376.4			201.3			829.6			485.7
NGL transportation, fractionation and services		82.3			45.8			215.1			138.5
Storage, terminaling and export		82.5			87.7			285.3			273.1
Other		18.6			6.8			54.3			33.6
Total fees from midstream services		559.8			341.6			1,384.3			930.9

Total revenues	$	5,360.1		$	4,459.7		$	16,375.0		$	11,508.2

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021

2020

Sales of commodities:

Revenue recognized from contracts with customers:

Natural gas

$
916.1

$
351.1

$
2,371.3

$
893.9

NGL

3,185.0

1,312.9

8,278.4

3,382.0

Condensate and crude oil

100.7

54.4

256.2

217.8

Petroleum products

—

13.2

—

69.8

4,201.8

1,731.6

10,905.9

4,563.5

Non-customer revenue:

Derivative activities - Hedge

(100.4
)

19.2

(303.8
)

139.4

Derivative activities - Non-hedge (1)

16.7

90.0

(24.8
)

197.9

(83.7
)

109.2

(328.6
)

337.3

Total sales of commodities

4,118.1

1,840.8

10,577.3

4,900.8

Fees from midstream services:

Revenue recognized from contracts with customers:

Gathering and processing

201.3

123.7

485.7

347.1

NGL transportation, fractionation and services

45.8

43.8

138.5

116.7

Storage, terminaling and export

87.7

96.6

273.1

285.5

Other

6.8

10.2

33.6

37.4

Total fees from midstream services

341.6

274.3

930.9

786.7

Total revenues

$
4,459.7

$
2,115.1

$
11,508.2

$
5,687.5

(1)

Represents derivative activities that are not designated as hedging instruments under ASC 815.

~~(1)~~

~~Represents derivative activities that are not designated as hedging instruments under ASC 815.~~

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

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, we announced the transfer 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 MMcf/d cryogenic natural gas processing plant (the “Heim Plant”). The Heim Plant, which commenced operations in the third quarter of 2021, processes natural gas production from the Permian Basin.

In August 2021, 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”~~plant”). The Legacy ~~Plant~~plant commenced operations in the third quarter of 2022.

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

In ~~November 2021,~~August 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 (the “Greenwood plant”). The Greenwood plant is expected to ~~meet the future infrastructure needs of our producers given our expectation for increasing production beyond the Legacy Plant.~~

~~In November 2021, we announced an update to our capital allocation strategy, including that for~~begin operations late in the fourth quarter of ~~2021,~~2023.

In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we ~~intend~~announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Midway plant”). The Midway plant is expected to ~~recommend~~begin operations in the second quarter of 2023. In conjunction with the commencement of operations of the Midway plant, we expect to idle the Sand Hills plant.

In July 2022, we acquired a 230 MMcf/d cryogenic natural gas processing plant, which was under construction at the time of acquisition, in Permian Delaware (the "Red Hills VI plant") as part of our ~~board~~acquisition of ~~directors~~certain assets in the Delaware Basin. The Red Hills VI plant commenced operations at the end of the third quarter of 2022.

In November 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Wildcat II plant”). The Wildcat II plant is expected to begin operations in the first quarter of 2024.

In August 2022, we announced plans to construct a new 120 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 9”). Train 9 is expected to begin operations in the second quarter of 2024.

In November 2022, we announced plans to construct a new NGL pipeline (the “Daytona NGL Pipeline”) as an ~~increase~~addition to our common ~~dividend~~carrier Grand Prix NGL Pipeline system. The pipeline will transport NGLs from the Permian Basin and connect to ~~$0.35 per common share or $1.40 per common share annualized.~~the 30-inch diameter segment of our Grand Prix NGL Pipeline in North Texas, where volumes will be transported to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. The ~~initial recommended common dividend per share increase~~Daytona NGL Pipeline will be supported by our volumes and other third-party customer volumes, and is expected to be ~~effective for~~in service by the ~~fourth quarter~~end of ~~2021~~2024, at an estimated cost of approximately $650 million. Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"), of which we own 75% and ~~payable in February 2022.~~Blackstone Energy Partners owns 25%, will own the Daytona NGL Pipeline and each member will fund their respective share of the pipeline’s cost based on their ownership percentage. We are constructing and expect to operate the Daytona NGL Pipeline. We expect to ~~continue to simplify our capital structure~~fund the construction of the Daytona NGL Pipeline through ~~repurchase~~the utilization of ~~our~~operating cash flows and available liquidity.

In January 2022, we completed the purchase of all of Stonepeak Infrastructure Partners’ (“Stonepeak”) interests in our development company joint ventures (“DevCo JVs”) for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75% interest in the Grand Prix Joint Venture, a 100% interest in the 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 DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

In April 2022, we completed the bolt-on acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9 million (the “South Texas Acquisition”), subject to customary closing adjustments. We expect to make a final closing adjustment payment of approximately $1.5 million in the fourth quarter of 2022. 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 two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and have been prospectively consolidated beginning in the second quarter of 2022.

In May 2022, we completed the sale of Targa GCX Pipeline LLC to a third party for $857.0 million (the “GCX Sale”). As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment ~~vehicles affiliated with Stonepeak Infrastructure Partners~~in our Consolidated Statements of Operations in the second quarter of 2022.

The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing services in the Delaware Basin, through owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets increase our footprint in and are integrated into our Permian Delaware operations.

For further details on our acquisitions and divestitures, see Note 4 - Joint Ventures, Acquisitions and Divestitures and Note 6 - Investments in Unconsolidated Affiliates to our Consolidated Financial Statements.

For the three months ended September 30, 2022, we repurchased 1,156,832 shares of our common stock at a weighted average price of $63.06 for a total net cost of $72.9 million. For the nine months ended September 30, 2022, we repurchased 3,016,556 shares of our common stock at a weighted average price of $65.23 for a total net cost of $196.8 million. There was $171.8 million remaining under our $500 million common share repurchase program as of September 30, 2022.

In May 2022, we redeemed in ~~January 2022~~full all of our issued and ~~the redemption of~~ 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.

Following the redemption, we have no Series A ~~Preferred”) over time, once~~Preferred outstanding and all rights of the ~~redemption price steps down~~holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our Consolidated Financial Statements.

In July 2022, we completed an underwritten public offering of (i) $750.0 million in ~~March 2022, while continuing to invest in accretive growth opportunities across~~aggregate principal amount of 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, the Partnership issued $1.0 billion of 4%~~5.200% Senior Notes due ~~2032,~~2027 (the “5.200% Notes”) and (ii) $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the “6.250% Notes”), resulting in net proceeds of approximately ~~$991 million. A portion of~~$1.2 billion. We used the net proceeds from the issuance ~~were used~~ to fund a portion of the ~~concurrent cash tender offer~~Delaware Basin Acquisition.

In July 2022, we entered into the Term Loan Agreement with Mizuho Bank, Ltd. as the Administrative Agent and a lender, and other lenders party thereto (the ~~“February Tender Offer”~~“Term Loan Facility”). The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility. The Term Loan Facility matures in July 2025. We used the proceeds to fund a portion of the Delaware Basin Acquisition.

In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”). Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and ~~subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025 (the “5⅛% Notes”),~~re-issued from time to time, with the ~~remainder used for repayment of borrowings~~maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the ~~Partnership’s senior secured~~$2.75 billion TRGP revolving credit facility (the ~~“TRP~~“TRGP Revolver”) ~~and our senior secured revolving credit facility (the “TRC Revolver”). As a result of~~equal to the February Tender Offer and the subsequent redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

~~Additionally, Targa Pipeline Partners LP (“TPL”) redeemed all of the~~aggregate amount 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~~Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP 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,~~In September 2022, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to, among other things, 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~~$800.0 million and to extend the facility termination date to ~~April 21, 2022.~~September 1, 2023.

For additional information about our recent debt-related transactions, see Note 57 - Debt Obligations to our ~~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 operations across Texas, 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 facilities experienced temporary outages, all facilities have since returned to full operations 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.”Consolidated Financial Statements.

In January 2022, the Internal Revenue Service (“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 have responded to information requests from the IRS and ~~2016. The~~do not anticipate material changes in prior year taxable income.

On October 6, 2021 and April 7, 2022, we received notice from the IRS ~~completed their examination without proposing any adjustments,~~that it intends to audit three direct 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.

On ~~December 17, 2020, FERC issued an Order Establishing Index Level establishing an index level~~indirectly wholly-owned subsidiaries of the ~~Producer Price Index~~Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for ~~Finished Goods plus 0.78%~~federal tax purposes for the ~~five-year period commencing July 1, 2021,~~2019 and ~~ending June 30, 2026 (“December~~ 2020 ~~Order”). On May 14, 2021, FERC published a revised oil pricing index factor utilizing~~tax years. We are responding to the ~~oil pricing index factor established in~~information requests from the December 2020 Order, resulting in a negative percent change for the index year July 1, 2021, through June 30, 2022. This means that the ceiling level for certain oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate must decrease 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 IRS~~(“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 methodology for the next five-year term of 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.

on these audits. The Company is not aware of any potential audit findings that would give rise to adjustments to taxable income and does not anticipate material changes related to these audits.

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~~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.~~flow and adjusted operating margin (segment).

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:

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

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(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
%
Fees from midstream services

341.6

274.3

67.3

25
%

930.9

786.7

144.2

18
%
Total revenues

4,459.7

2,115.1

2,344.6

111
%

11,508.2

5,687.5

5,820.7

102
%
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
%
Operating expenses (1)

189.4

162.2

27.2

17
%

545.3

506.8

38.5

8
%
Depreciation and amortization expense

222.8

203.7

19.1

9
%

650.9

647.3

3.6

1
%
General and administrative expense

67.3

58.6

8.7

15
%

192.4

180.6

11.8

7
%
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
%)
Income (loss) from operations

366.5

295.5

71.0

24
%

956.4

(1,568.9
)

2,525.3

161
%
Interest expense, net

(91.0
)

(97.7
)

6.7

7
%

(284.2
)

(292.4
)

8.2

3
%
Equity earnings (loss)

14.3

18.6

(4.3
)

(23
%)

38.9

54.1

(15.2
)

(28
%)
Gain (loss) from financing activities

—

(13.7
)

13.7

100
%

(16.6
)

47.4

(64.0
)

(135
%)
Other, net

0.2

1.4

(1.2
)

NM

0.3

2.2

(1.9
)
NM

Income tax (expense) benefit

(2.0
)

(31.9
)

29.9

94
%

(23.5
)

286.6

(310.1
)

(108
%)
Net income (loss)

288.0

172.2

115.8

67
%

671.3

(1,471.0
)

2,142.3

146
%
Less: Net income (loss) attributable to noncontrolling interests

105.8

102.9

2.9

3
%

286.5

116.5

170.0

146
%
Net income (loss) attributable to Targa Resources Corp.

182.2

69.3

112.9

163
%

384.8

(1,587.5
)

1,972.3

124
%
Dividends on Series A Preferred Stock

21.8

22.9

(1.1
)

(5
%)

65.5

68.8

(3.3
)

(5
%)
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
%
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
%
(1)

Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”

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

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

The increase in commodity sales reflects higher ~~NGL,~~ natural gas and condensate prices ($~~2,259.0~~867.5 million) and higher NGL and natural gas volumes ($~~226.6~~110.3 million), partially offset by lower NGL prices ($132.7 million) and the unfavorable impact of hedges ($~~192.8~~159.7 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the Delaware Basin, and transportation and fractionation fees, partially offset by lower ~~terminaling~~export volumes.

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

The increase in operating expenses is due to higher compensation and benefits, maintenance and rental costs primarily due to increased activity, system expansions, the acquisition of certain assets in the Delaware Basin and South Texas and inflation.

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

The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and the shortening of depreciable lives of certain assets that have been, or will be, idled, partially offset by a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.

The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.

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

The decrease in equity earnings is primarily due to the GCX Sale, partially offset by lower losses resulting from the purchase of our remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates. See Note 4 – Joint Ventures, Acquisitions and Divestitures to our Consolidated Financial Statements for further discussion.

The increase in income tax expense is primarily due to a lower return-to-provision benefit in 2022 compared to 2021.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the DevCo JV Repurchase, partially offset by accretion of noncontrolling interests in certain joint ventures in WestTX and higher income allocated to noncontrolling interest holders in the Grand Prix Joint Venture.

The decrease in dividends on Series A Preferred is due to the full redemption of all of our issued and outstanding shares of Series A Preferred during 2022. See Note 9 – Preferred Stock for further discussion.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($4,224.4 million) and higher NGL and natural gas volumes ($611.7 million), partially offset by the unfavorable impact of hedges ($414.1 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the Delaware Basin, transportation and 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.

~~Operating~~The increase in operating expenses ~~were higher~~is due to ~~increased labor~~higher maintenance, compensation and benefits, and rental costs ~~and higher repairs and maintenance~~ primarily due to increased activity, ~~levels~~system expansions, the acquisition of certain assets in the Delaware Basin and ~~system expansions.~~South Texas and inflation, partially offset by the impact of 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 in depreciation and amortization expense is primarily due to ~~a full quarter~~the acquisition of ~~depreciation on major growth capital projects previously placed~~certain assets in ~~service, including the addition of fractionation trains in Mont Belvieu,~~South Texas and ~~additional processing plants~~the Delaware Basin, shortening of the depreciable lives of certain assets that have been, or will be, idled and ~~associated infrastructure in the Permian Basin. The increase in depreciation and amortization expense was~~impact of system expansions on our asset base, partially offset by a lower depreciable base associated with assets that were impaired during the ~~sale~~fourth quarter of ~~assets in Channelview, Texas, in October 2020.~~2021.

The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and anprofessional fees.

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~~higher net borrowings and higher non-cash interest expense related to an increase in the mandatorily redeemable preferred interest liability, 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~~change in ~~a $13.7 million net loss from financing activities.~~

~~The decrease in income tax expense is primarily due to a larger release~~fair value 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~~mandatorily redeemable preferred interest, 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.~~

~~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 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~~ capitalized interest resulting from ~~lower~~higher growth capital ~~investments.~~investments and lower commitment fees.

The decrease in equity earnings is primarily due to the GCX Sale and lower earnings from our ~~investments~~investment in ~~Gulf Coast Fractionators and Cayenne Pipeline~~Little Missouri 4 LLC, partially offset by ~~an increase~~lower losses resulting from ~~Little Missouri~~the purchase of our remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and lower losses from Gulf Coast Fractionators. See Note 4 ~~LLC (“Little Missouri 4”).~~– Joint Ventures, Acquisitions and Divestitures to our Consolidated Financial Statements for further discussion.

During ~~2021,~~2022, 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”). In addition, the Partnership redeemed the ~~5⅛%~~5.375% Senior Notes ~~the TPL Notes~~due 2027 and the ~~4¼%~~5.875% Senior Notes ~~resulting~~due 2026. These transactions resulted in a ~~$16.6 million~~ net loss from financing activities. During ~~2020,~~2021, the Partnership ~~repurchased~~redeemed its 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due 2023. In addition, Targa Pipeline Partners LP redeemed its 4.750% Senior Notes due 2021 and the 5.875% Senior Notes due 2023. These transactions resulted in a ~~portion of its outstanding senior notes on~~net loss from financing activities. See Note 7 – Debt Obligations for further discussion.

During 2022, we completed the ~~open market,~~GCX Sale resulting in a ~~$47.4 million net~~ gain from ~~financing activities.~~sale of an equity method investment. See Note 4 – Joint Ventures, Acquisitions and Divestitures for further discussion.

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

The ~~increase~~decrease in net income (loss) attributable to noncontrolling interests is primarily due to ~~impairment losses allocated to~~the DevCo JV Repurchase, partially offset by accretion of noncontrolling ~~interest holders~~interests in ~~the first quarter of 2020~~certain joint ventures in WestTX and higher income allocated to noncontrolling ~~interest~~interests holders in the Grand Prix Joint ~~Venture. The increase in net income attributable to noncontrolling interests was partially offset by the impact of the redemption of the Partnership’s preferred units in December 2020.~~Venture, Centrahoma Processing, LLC, Carnero Joint Venture and Venice Energy Services, L.L.C.

The decrease in dividends on Series A Preferred is due to the ~~partial repurchase~~full redemption of all of our issued and outstanding shares of Series A Preferred ~~in December 2020.~~during 2022. See Note 9 – Preferred Stock for further discussion.

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(In millions, except operating statistics and price amounts)

Operating margin
$

361.4

$

261.0

$

100.4

38
%

$

938.2

$

753.7

$

184.5

24
%
Operating expenses (1)

122.8

102.1

20.7

20
%

343.1

313.6

29.5

9
%
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)

Permian Midland (5)

2,109.2

1,811.5

297.7

16
%

1,900.7

1,722.1

178.6

10
%
Permian Delaware

842.7

758.1

84.6

11
%

805.9

712.4

93.5

13
%
Total Permian

2,951.9

2,569.6

382.3

2,706.6

2,434.5

272.1

SouthTX

180.5

233.6

(53.1
)

(23
%)

184.0

261.5

(77.5
)

(30
%)
North Texas

180.7

197.8

(17.1
)

(9
%)

179.2

206.3

(27.1
)

(13
%)
SouthOK

420.6

386.9

33.7

9
%

402.6

463.3

(60.7
)

(13
%)
WestOK

219.4

233.6

(14.2
)

(6
%)

211.6

258.7

(47.1
)

(18
%)
Total Central

1,001.2

1,051.9

(50.7
)

977.4

1,189.8

(212.4
)

Badlands (6)

135.2

137.0

(1.8
)

(1
%)

137.8

136.1

1.7

1
%
Total Field

4,088.3

3,758.5

329.8

3,821.8

3,760.4

61.4

Coastal

527.1

522.8

4.3

1
%

598.3

672.9

(74.6
)

(11
%)

Total

4,615.4

4,281.3

334.1

8
%

4,420.1

4,433.3

(13.2
)

—

NGL production, MBbl/d (4)

Permian Midland (5)

307.3

253.0

54.3

21
%

274.8

247.6

27.2

11
%
Permian Delaware

119.8

105.3

14.5

14
%

109.3

97.1

12.2

13
%
Total Permian

427.1

358.3

68.8

384.1

344.7

39.4

SouthTX

24.2

29.2

(5.0
)

(17
%)

22.6

28.7

(6.1
)

(21
%)
North Texas

21.0

23.7

(2.7
)

(11
%)

20.2

24.5

(4.3
)

(18
%)
SouthOK

52.1

45.9

6.2

14
%

48.8

54.6

(5.8
)

(11
%)
WestOK

15.7

19.3

(3.6
)

(19
%)

16.2

21.2

(5.0
)

(24
%)
Total Central

113.0

118.1

(5.1
)

107.8

129.0

(21.2
)

Badlands

16.2

17.0

(0.8
)

(5
%)

16.0

16.3

(0.3
)

(2
%)
Total Field

556.3

493.4

62.9

507.9

490.0

17.9

Coastal

28.0

32.5

(4.5
)

(14
%)

34.5

41.5

(7.0
)

(17
%)

Total

584.3

525.9

58.4

11
%

542.4

531.5

10.9

2
%
Crude oil, Badlands, MBbl/d

140.8

146.4

(5.6
)

(4
%)

138.7

160.4

(21.7
)

(14
%)
Crude oil, Permian, MBbl/d

34.1

44.6

(10.5
)

(24
%)

35.3

45.3

(10.0
)

(22
%)
Natural gas sales, BBtu/d (4)

2,319.9

2,032.3

287.6

14
%

2,162.5

2,079.3

83.2

4
%
NGL sales, MBbl/d (4)

412.6

389.5

23.1

6
%

384.7

406.0

(21.3
)

(5
%)
Condensate sales, MBbl/d

15.4

13.6

1.8

13
%

15.3

16.1

(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
%
NGL, $/gal

0.69

0.29

0.40

138
%

0.56

0.24

0.32

133
%
Condensate, $/Bbl

64.41

43.49

20.92

48
%

56.86

38.56

18.30

47
%
(1)

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

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:

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

The increase in adjusted ~~gross~~operating margin was due to higher natural gas inlet volumes, higher realized commodity prices and higher fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to both the acquisition of certain assets in the Delaware Basin and increased producer activity supported by the addition of the Legacy Plant during the third quarter of 2022. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity. The increase in volumes in the Badlands and the Coastal region was attributable to increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and third quarters of 2022. Additionally, higher volumes in the Permian, the addition of the Legacy plant in the third quarter of 2022, a full quarter of operations at the Heim plant in 2022 and inflation impacts resulted in increased costs primarily in compensation and benefits, rentals, materials, taxes and chemicals.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

The increase in adjusted operating margin was due to higher realized commodity prices, ~~and~~ higher natural gas inlet volumes and higher fees resulting in increased margin ~~primarily~~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~~both the acquisition of certain assets in the Delaware Basin and increased producer activity ~~as well as~~supported by the addition of the ~~Gateway~~Legacy and Heim plants during the third ~~quarters~~quarter of ~~2020~~2022 and 2021, respectively. ~~In the Badlands and Coastal regions, natural~~Natural gas ~~inlet~~ volumes ~~were relatively flat, while~~ in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity. The decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to lower ~~production~~producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and ~~continued low producer activity. Total crude oil volumes decreased~~the Delaware Basin in the ~~Badlands~~second and ~~the Permian due to lower production.~~

~~Operating expenses were~~third quarters of 2022. Additionally, higher ~~due to increased activity levels~~volumes in the Permian, ~~and~~ the addition of the ~~Gateway~~Legacy and Heim plants in the third ~~quarters~~quarter of ~~2020~~2022 and 2021, ~~respectively, which~~and inflation impacts resulted in increased costs primarily in compensation and benefits, materials, chemicals, contract labor, rentals and taxes.

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin, partially offset by lower LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and higher fees. Marketing margin increased due to greater optimization opportunities. LPG export margin decreased primarily due to higher fuel and power costs ~~materials~~ and ~~chemicals.~~lower volumes.

The increase in operating expenses was due to higher repairs and maintenance and higher compensation and benefits.

Nine Months Ended September 30, ~~2021~~2022 Compared to Nine Months Ended September 30, ~~2020~~2021

The increase in adjusted ~~gross~~operating 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 in the third quarter of 2021, which resulted in increased labor costs and materials.

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

~~The increase in adjusted gross margin was primarily~~ due to higher pipeline transportation and fractionation ~~volumes,~~margin, partially offset by ~~lower LPG export volumes and~~ lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing ~~systems. LPG export volumes were lower due~~systems and higher fees. Higher optimization margin attributable to ~~reduced short-term loading capacity as a result of repairs and maintenance that were completed~~the winter storm resulted in ~~the third quarter of~~higher marketing margin in 2021. ~~Marketing margin decreased due to fewer optimization opportunities.~~

~~Operating~~The increase in operating expenses ~~were higher~~was primarily 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~~compensation and ~~the sale of assets in Channelview, Texas, in 2020.~~

~~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,benefits, partially offset by lower ~~LPG export terminal fees.~~taxes.

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.Other

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~~“Item 3. – Quantitative and Qualitative Disclosures About Market Risk.”

As of September 30, ~~2021,~~2022, inclusive of our consolidated joint venture accounts, we had ~~$228.6~~$192.9 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.

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~~TRGP Revolver, ~~the TRP Revolver, and the Partnership’s~~Commercial Paper Program, 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,~~28, 2022, was:

Other potential capital resources associated with our existing arrangements ~~include:~~includes our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 17, 2027.

On April 21, 2021, we amended the Partnership’s 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 extend the facility termination date to April 21, 2022.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. ~~These~~As of September 30, 2022, we had $47.2 million letters of credit ~~reflect our non-investment grade status, as assigned to us by Fitch, Moody’s and S&P.~~outstanding under the TRGP Revolver. 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;~~manage, and valuation; (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~~ 2022 decreased ~~$555.9~~$367.7 million compared to December 31, ~~2020.~~ 2021. The decrease was primarily due to higher net borrowing on the Securitization Facility, 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,~~ partially offset by higher receivables resulting from higher commodity prices and an increase ~~in NGLs~~to NGL inventory.

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~~TRGP Revolver, ~~the TRP Revolver and the Partnership’s~~Commercial Paper Program, 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, we closed on the sale of a 45% interest in Targa Badlands LLC to GSO Capital Partners and Blackstone Tactical Opportunities. Targa Badlands LLC is a discrete entity and the assets and credit of Targa Badlands LLC are not available to satisfy the debts and other obligations of Targa or its other subsidiaries.

In February ~~2021,~~2022, we entered into the ~~Partnership issued $1.0 billion~~TRGP Revolver. The TRGP Revolver provides for a revolving credit 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 connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver and the Partnership Revolver. In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC and Fitch Ratings Inc., and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. 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 February Tender Offer and subsequent redemption payment for 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~~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 and Targa Resources Partners Finance Corporation under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of September 30, 2022, $5.0 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.

~~Additionally, TPL redeemed all~~In April 2022, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052, resulting in net proceeds of approximately $1.5 billion. A portion of the net proceeds from the issuance was 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 of the net proceeds used for repayment of the outstanding ~~TPL Notes on February 22, 2021 with available liquidity~~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 a loss due to debt extinguishment of ~~$1.9 million.~~$33.8 million comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.

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. 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 for additional information.

In July 2022, we completed an underwritten public offering of the 5.200% Notes and the 6.250% Notes, resulting in net proceeds of approximately $1.2 billion. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.

In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility. The Term Loan Facility matures in July 2025. We used the proceeds to fund a portion of the Delaware Basin Acquisition.

In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. As of September 30, 2022, we had $632.0 million outstanding under the Commercial Paper Program.

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.

On April 21, 2021, we amended the 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 extend the facility termination date to April 21, 2022.

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,~~2022, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

The primary drivers of cash flows from operating activities ~~are~~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,~~transportation; (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude ~~oil~~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.

~~Cash~~The increase in net cash used in investing activities ~~decreased in 2021 compared to 2020,~~was primarily due to ~~lower~~the outlays for the Delaware Basin Acquisition and South Texas Acquisition. Additionally, there were higher outlays for property, plant and equipment ~~of $481.5 million,~~ resulting from construction activities associated with our Permian expansions, including the ~~completion of additional fractionation trains in Mont Belvieu, Texas (collectively, “Trains 7~~Legacy, Red Hills VI, Midway, Legacy II and ~~8”), the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine~~Greenwood plants, and ~~additional processing plants and associated infrastructure in the Permian Basin in 2020,~~Train 9, 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.~~GCX Sale.

In ~~2021~~,The change in net cash ~~used in~~provided by (used in) financing activities iswas primarily ~~due to repayments~~ ~~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 distributions to noncontrolling interests, partially offset by a net increase of debt outstanding. Our debt outstanding increased due to net borrowings ~~under our credit facilities,~~of debt in 2022, as compared to net repayments of debt in 2021, partially offset by ~~redemptions~~the redemption of the Series A Preferred Stock and repurchases of ~~a portion~~non-controlling interests in the DevCo JVs and common stock during 2022. Additionally, higher dividends were paid in 2022 due to the increase in our common stock dividends from $0.10 to $0.35 per common share in January 2022.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Our 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 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 Statement of Operations information for the Obligated Group based on Rule 13-01 of the ~~outstanding senior notes~~SEC’s Regulation S-X.

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated 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 ~~Partnership.~~

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

In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a ~~liquidation~~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 ~~$1,000 per share~~the shares redeemed was $223.7 million, of which $215.5 million was 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 ~~bears~~all rights of the holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our Consolidated Financial Statements.

Prior to the redemption of our Series A Preferred in May 2022, our Series A Preferred bore a cumulative 9.5% fixed dividend payable ~~quarterly 45 days after~~at the end of each fiscal quarter.

~~Cash dividends of $65.5 million were paid to holders of the Series A Preferred during~~ During the nine months ended September 30, ~~2021. As~~2022, we paid $51.8 million of ~~September 30, 2021, cash~~ dividends ~~accrued for our Series A Preferred were $21.8 million, which will be paid on November 12, 2021.~~to preferred shareholders.

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

With our recent announcements regarding the current expansion of natural gas processing in our Permian region, coupled with the construction of Train 9 fractionator in Mont Belvieu, we currently estimate that in ~~2021~~2022 we will invest ~~approximately $350~~between $1.1 to ~~$450 million~~$1.2 billion 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,~~2022, there were ~~$65.7~~$70.6 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,~~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:~~2022:

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)~~decreased by ($~~83.7)~~243.2) million and $~~109.2~~($83.7) million during the three months ended September 30, 2022 and 2021 and ~~2020~~($742.7) million and ($328.6) ~~million and $337.3~~ million during the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of ($~~51.2)~~316.7) million at December 31, ~~2020~~2021 to ~~a net liability position of~~ ($~~527.4)~~330.1) million at September 30, ~~2021.~~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~~TRGP Revolver, the ~~TRP Revolver~~Commercial Paper Program, the Securitization Facility, and the ~~Securitization~~Term Loan Facility. As of September 30, ~~2021,~~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~~TRGP Revolver, the ~~TRP Revolver~~Commercial Paper Program, the Securitization Facility and the ~~Securitization~~Term Loan Facility will also increase. As of September 30, ~~2021, the Partnership~~2022, we had ~~$340.0 million~~$3.4 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~~$34.3 million based on our September 30, ~~2021~~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, and would reduce our maximum loss due to counterparty credit risk by ~~$9.1~~$32.7 million as of September 30, ~~2021.~~2022. The range of losses attributable to our individual counterparties as of September 30, ~~2021~~2022 would be between ~~$9.4~~$0.1 million and ~~$10.8~~$57.6 million, depending on the counterparty in default.

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~~$2.2 million and $0.1 million as of September 30, ~~2021~~2022 and December 31, ~~2020. Changes~~2021, respectively. The change in the allowance for doubtful accounts ~~were not material for~~was primarily due to the ~~three and nine months ended September 30, 2021.~~Delaware Basin Acquisition during the third quarter of 2022.

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

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, ~~2021,~~ 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~~On July 29, 2022, we completed the Delaware Basin Acquisition. As part of the ongoing integration of the acquired business, we are in the process of incorporating the controls and related procedures. Except for the Delaware Basin Acquisition, there has been no ~~changes~~change in our internal control over financial reporting ~~that occurred~~(as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the ~~quarter~~three months ended September 30, 2022 that has materially affected, or ~~are~~is reasonably likely to materially affect, our internal control over financial ~~reporting, during our most recent fiscal quarter.~~reporting.

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. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We are in the process of preparing our further appeal to the Supreme Court of Texas. The cumulative amount of interest on the award through September 30, 2022, if accrued, would have been approximately $39.6 million.

Additional information required for this item is provided in Note 1314 – 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. All of these risks and uncertainties, including ~~those risks~~the risk discussed below, could adversely affect our business, financial condition and/or results of operations.

~~Weather~~Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes 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 cash flows.

U.S. federal and state legislation is periodically proposed that would, if enacted into law, make significant changes to tax laws and could materially increase our tax obligations, adversely affecting our financial ~~condition.~~condition, results of operations and cash flows. For example, on August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”) which includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending with such taxable year exceeds $1 billion.

Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate being an applicable corporation in the near term, but we are likely to become an applicable corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future year. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years.

The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. In the future the U.S. Department of the Treasury and the Internal Revenue Service are expected to release regulations and interpretive guidance relating

to such legislation, and any significant variance from our current interpretation could result in a change in our analysis of the application of the CAMT to us.

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~~2022 and December 31, ~~2020~~2021		4

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

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

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

Consolidated Statements of Cash Flows for the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021		11

Notes to Consolidated Financial Statements		12

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2832

Item 3. Quantitative and Qualitative Disclosures About Market Risk		4448

Item 4. Controls and Procedures		4751

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		4852

Item 1A. Risk Factors		4852

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4853

Item 3. Defaults Upon Senior Securities		4953

Item 4. Mine Safety Disclosures		4953

Item 5. Other Information		4953

Item 6. Exhibits		4953

SIGNATURES

Signatures		5155


Bbl		Barrels (equal to 42 U.S. gallons)
BBtu		Billion British thermal units
Bcf		Billion cubic feet
Btu		British thermal units, a measure of heating value
/d		Per day
~~GAAP~~FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
gal		U.S. gallons
~~LPG~~LIBOR		~~Liquefied petroleum gas~~London Inter-Bank Offered Rate
~~MBbl~~LPG		~~Thousand barrels~~Liquefied petroleum gas
~~MMBbl~~MBbl		~~Million~~Thousand barrels
~~MMBtu~~MMBbl		Million barrels
MMBtu		Million British thermal units
MMcf		Million cubic feet
MMgal		Million U.S. gallons
NGL(s)		Natural gas liquid(s)
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
SCOOP		South Central Oklahoma Oil Province
~~STACK~~SOFR		Secured Overnight Financing Rate
STACK		Sooner Trend, Anadarko, Canadian and Kingfisher


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		213,394		175,687		102,347		19,895		—		—
Natural Gas	Basis Swaps	MMBtu/d		483,779		308,740		250,000		225,000		110,041	Basis Swaps	MMBtu/d		452,989		425,247		280,000		244,267		55,000		10,000
NGL	Swaps	Bbl/d		39,568		29,424		12,557		2,186		0	Swaps	Bbl/d		48,617		43,115		20,350		2,480		—		—
NGL	Futures	Bbl/d		45,315		740		0		0		0	Futures	Bbl/d		66,630		3,614		—		—		—		—
Condensate	Swaps	Bbl/d		5,029		3,853		2,155		265		0	Swaps	Bbl/d		6,547		6,427		3,089		427		—		—

	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	)


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


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



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

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

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

	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

	Nine Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	512.9	$	4,172.0	$	215.9	$	—		$	4,900.8
Fees from midstream services		354.5		432.2		—		—			786.7
		867.4		4,604.2		215.9		—			5,687.5
Intersegment revenues
Sales of commodities		1,444.3		140.1		—		(1,584.4	)		—
Fees from midstream services		4.9		23.8		—		(28.7	)		—
		1,449.2		163.9		—		(1,613.1	)		—
Revenues	$	2,316.6	$	4,768.1	$	215.9	$	(1,613.1	)	$	5,687.5
Operating margin (1)	$	753.7	$	806.0	$	215.9	$	—		$	1,775.6
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	$	218.0	$	375.5	$	—	$	16.8		$	610.3


	Gathering and Processing		Logistics and Transportation		Other			Total		Gathering and Processing		Logistics and Transportation		Other
	(In millions)									(In millions)
Three Months Ended:
September 30, 2022										$	564.6	$	340.2	$	(112.2	)
September 30, 2021	$	361.4	$	280.7	$	13.5		$	655.6		361.4		280.7		13.5
September 30, 2020		261.0		280.4		88.6			630.0

Nine Months Ended:
September 30, 2022										$	1,437.0	$	1,014.6	$	(294.9	)
September 30, 2021	$	938.2	$	920.5	$	(55.6	)	$	1,803.1		938.2		920.5		(55.6	)
September 30, 2020		753.7		806.0		215.9			1,775.6


	Three Months Ended September 30, 2022								Three Months Ended September 30, 2021
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		20.3	$	(3.58	)	$	(72.7	)		20.5	$	(1.52	)	$	(31.2	)
NGL (MMgal)		194.9		(0.25	)		(49.4	)		150.4		(0.35	)		(52.4	)
Crude oil (MBbl)		0.6		(26.83	)		(16.1	)		0.5		(18.80	)		(9.4	)
						$	(138.2	)						$	(93.0	)


	Consolidated Total
	(In millions)
Cash on hand (1)	$	546.7
Total availability under the Securitization Facility		800.0
Total availability under the TRGP Revolver and Commercial Paper Program		2,750.0
		4,096.7

Less: Outstanding borrowings under the Securitization Facility		(800.0	)
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program		(1,117.0	)
Outstanding letters of credit under the TRGP Revolver		(33.2	)
Total liquidity	$	2,146.5

	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
	September 30, 2022			December 31, 2021
	(In millions)
ASSETS
Current assets	$	1,471.0		$	832.9
Current assets - affiliates		58.9			24.4
Long-term assets		10,064.6			6,253.9
Long-term assets - affiliates		10.5			10.5
Total assets	$	11,605.0		$	7,121.7

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities	$	1,945.5		$	1,525.6
Current liabilities - affiliates		221.0			195.8
Long-term liabilities		11,108.1			6,875.5
Series A Preferred		—			749.7
Targa Resources Corp. stockholders' equity		(1,669.6	)		(2,224.9	)
Total liabilities and owners' equity	$	11,605.0		$	7,121.7

Summarized Combined Statement of Operations Information
	Nine Months Ended			Year Ended
	September 30, 2022			December 31, 2021
	(In millions)
Revenues	$	16,747.6		$	16,900.5
Operating income (loss)		(24.2	)		5.7
Net income (loss)		33.5			(371.0	)
Dividends on Series A Preferred		30.0			87.3


										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	)	$	(383.6	)	$	(288.3	)	$	(478.9	)
NGLs		(334.8	)		(251.2	)		(418.4	)		57.3			159.4			(44.6	)
Crude oil		(52.3	)		(33.4	)		(71.2	)		(3.8	)		25.1			(32.7	)
Total	$	(527.4	)	$	(378.3	)	$	(676.5	)	$	(330.1	)	$	(103.8	)	$	(556.2	)


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, 2022 - July 31, 2022		514,230	$	58.58		512,336	$	214,706
August 1, 2022 - August 31, 2022		384,118	$	68.72		261,378	$	196,707
September 1, 2022 - September 30, 2022		386,421	$	65.08		383,118	$	171,766


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		Second Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit ~~3.2~~3.4 to Targa Resources Corp.’s ~~Current~~Quarterly Report on Form ~~8-K~~10-Q filed ~~December 16, 2010~~on May 5, 2022 (File No. 001-34991)).

~~3.5~~4.1		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		Third Supplemental Indenture, dated as of July 7, 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 July 7, 2022 (File No. 001-34991)).

4.3		Form of Notes (included in Exhibit 4.3 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K filed July 7, 2022 (File No. 001-34991)).


Number		Description
10.1*		Supplemental Indenture dated September 17, 2021 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.

10.2*		~~Supplemental Indenture dated September 17, 2021~~August 2, 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.

10.310.2		Supplemental Indenture dated September 17, 2021 to Indenture dated April 12, 2018 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.4*		~~Supplemental Indenture dated September 17, 2021~~August 2, 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.

~~Number~~		~~Description~~
10.3*
10.5*		Supplemental Indenture dated ~~September 17, 2021~~August 2, 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.

10.610.4		Supplemental Indenture dated ~~September 17, 2021~~August 2, 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.

10.710.5		Supplemental Indenture dated ~~September 17, 2021~~August 2, 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.

31.110.6		Fourth Supplemental Indenture dated as of August 2, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee.

10.7		Thirteenth Amendment to Receivables Purchase Agreement, dated as of September 2, 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 September 6, 2022 (File No. 001-34991)).

10.8		Term Loan Agreement, dated as of July 12, 2022, among Targa Resources Corp., Mizuho Bank, Ltd., as administrative agent and a lender, and the other lenders parties thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 12, 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

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


	Targa Resources Corp.
	(Registrant)

Date: November ~~4, 2021~~3, 2022	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)