UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2023

or

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

For the transition period from _____ to _____

Commission File Number: 001-34991

 

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware	20-3701075
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
811 Louisiana Street, Suite 2100, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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

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

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

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

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

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

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

As of October 31, 2023, there were 222,975,600 shares of the registrant’s common stock, $0.001 par value, outstanding.

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022	4
Consolidated Statements of Operations for the three and nine months ended September 30, 2023 and 2022	5
Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2023 and 2022	6
Consolidated Statements of Changes in Owners’ Equity and Series A Preferred Stock for the three and nine months ended September 30, 2023 and 2022	7
Consolidated Statements of Cash Flows for the nine months ended September 30, 2023 and 2022	11
Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	43
Item 4. Controls and Procedures	45
PART II—OTHER INFORMATION
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3. Defaults Upon Senior Securities	47
Item 4. Mine Safety Disclosures	48
Item 5. Other Information	48
Item 6. Exhibits	48
SIGNATURES
Signatures	50

1

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (the “Partnership”), “we,” “us,” “our,” “Targa,” “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:

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

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

•our ability to access the capital markets, which will depend on general market conditions, including the impact of increased interest rates and the potential for additional increases, and associated Federal Reserve policies and potential economic recession, our credit ratings and debt obligations, and demand for our common equity, senior notes and commercial paper;

•downside commodity price volatility from a variety of potential factors;

•actions taken by other countries with significant hydrocarbon production;

•the timing and success of business development efforts;

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

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

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

•changes in laws and regulations, such as the Inflation Reduction Act of 2022 (the “IRA”), particularly with regard to taxes, safety and the protection of the environment;

•the impact of outbreaks of illnesses, pandemics or any other public health crises;

•weather and other natural phenomena, and related impacts;

•industry changes, including the impact of consolidations, changes in competition and the drive to reduce fossil fuel use and substitute alternative forms of energy for oil and gas;

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

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

•general economic, market and business conditions;

•the impact of disruptions in the bank and capital markets, including those resulting from lack of access to liquidity for banking and financial services firms; and

•the risks described in our Annual Report on Form 10-K for the year ended December 31, 2022 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

2

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, 2023 (“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:

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

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

	September 30, 2023			December 31, 2022
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	139.5		$	219.0
Trade receivables, net of allowances of $2.6 and $2.2 million at September 30, 2023 and December 31, 2022		1,241.1			1,408.4
Inventories		536.2			393.8
Assets from risk management activities		84.2			179.9
Other current assets		138.3			155.5
Total current assets		2,139.3			2,356.6
Property, plant and equipment, net		15,333.5			14,214.6
Intangible assets, net		2,446.6			2,734.6
Long-term assets from risk management activities		17.7			24.5
Investments in unconsolidated affiliates		138.3			131.3
Other long-term assets		114.2			98.4
Total assets	$	20,189.6		$	19,560.0
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	1,581.3		$	1,448.8
Accrued liabilities		292.0			289.5
Interest payable		101.0			174.0
Liabilities from risk management activities		105.8			320.1
Current debt obligations		602.0			834.3
Total current liabilities		2,682.1			3,066.7
Long-term debt		12,318.4			10,702.1
Long-term liabilities from risk management activities		34.8			140.1
Deferred income taxes, net		418.3			327.7
Other long-term liabilities		358.2			341.2
Contingencies (see Note 12)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero shares issued and outstanding as of September 30, 2023 and December 31, 2022), net of discount		—			—
Owners’ equity:
Targa Resources Corp. stockholders’ equity:
Common stock ($0.001 par value, 450,000,000 shares authorized as of September 30, 2023 and December 31, 2022)		0.2			0.2
Issued Outstanding
September 30, 2023 240,087,974 223,080,697
December 31, 2022 237,939,058 226,042,229
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		3,061.5			3,702.3
Retained earnings (deficit)		305.5			(626.8	)
Accumulated other comprehensive income (loss)		(5.3	)		54.7
Treasury stock, at cost (17,007,277 shares as of September 30, 2023 and 11,896,829 shares as of December 31, 2022)		(855.8	)		(464.7	)
Total Targa Resources Corp. stockholders’ equity		2,506.1			2,665.7
Noncontrolling interests		1,871.7			2,316.5
Total owners’ equity		4,377.8			4,982.2
Total liabilities, Series A Preferred Stock and owners’ equity	$	20,189.6		$	19,560.0

See notes to consolidated financial statements.

4

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Sales of commodities	$	3,374.3		$	4,800.3		$	10,314.0		$	14,990.7
Fees from midstream services		522.3			559.8			1,506.8			1,384.3
Total revenues		3,896.6			5,360.1			11,820.8			16,375.0
Costs and expenses:
Product purchases and fuel		2,690.0			4,306.3			7,777.9			13,557.8
Operating expenses		277.7			261.3			808.4			660.6
Depreciation and amortization expense		331.3			287.2			988.2			766.2
General and administrative expense		90.0			79.1			253.4			217.2
Other operating (income) expense		2.5			(3.8	)		2.0			(4.4	)
Income (loss) from operations		505.1			430.0			1,990.9			1,177.6
Other income (expense):
Interest expense, net		(175.1	)		(125.8	)		(509.8	)		(300.5	)
Equity earnings (loss)		3.0			1.7			6.2			8.7
Gain (loss) from financing activities		—			—			—			(49.6	)
Gain (loss) from sale of equity method investment		—			—			—			435.9
Other, net		(0.1	)		(14.6	)		(4.9	)		(14.6	)
Income (loss) before income taxes		332.9			291.3			1,482.4			1,257.5
Income tax (expense) benefit		(53.9	)		(12.0	)		(260.7	)		(122.0	)
Net income (loss)		279.0			279.3			1,221.7			1,135.5
Less: Net income (loss) attributable to noncontrolling interests		59.0			86.2			175.4			258.0
Net income (loss) attributable to Targa Resources Corp.		220.0			193.1			1,046.3			877.5
Premium on repurchase of noncontrolling interests, net of tax		—			—			490.7			53.1
Dividends on Series A Preferred Stock		—			—			—			30.0
Deemed dividends on Series A Preferred Stock		—			—			—			215.5
Net income (loss) attributable to common shareholders	$	220.0		$	193.1		$	555.6		$	578.9
Net income (loss) per common share - basic	$	0.97		$	0.85		$	2.44		$	2.54
Net income (loss) per common share - diluted	$	0.97		$	0.84		$	2.43		$	2.50
Weighted average shares outstanding - basic		223.8			226.6			225.2			227.6
Weighted average shares outstanding - diluted		225.1			230.3			226.5			231.5

See notes to consolidated financial statements.

5

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended September 30,
	2023								2022
	Pre-Tax			Related Income Tax		After Tax			Pre-Tax		Related Income Tax			After Tax
	(Unaudited)
	(In millions)
Net income (loss)						$	279.0							$	279.3
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	(153.8	)	$	34.9		(118.9	)	$	225.4	$	(50.4	)		175.0
Settlements reclassified to revenues		(22.2	)		5.0		(17.2	)		121.7		(27.0	)		94.7
Other comprehensive income (loss)		(176.0	)		39.9		(136.1	)		347.1		(77.4	)		269.7
Comprehensive income (loss)							142.9								549.0
Less: Comprehensive income (loss) attributable to noncontrolling interests							59.0								86.2
Comprehensive income (loss) attributable to Targa Resources Corp.						$	83.9							$	462.8

	Nine Months Ended September 30,
	2023									2022
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax			After Tax
	(Unaudited)
	(In millions)
Net income (loss)							$	1,221.7								$	1,135.5
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	39.6		$	(9.0	)		30.6		$	(136.7	)	$	30.5			(106.2	)
Settlements reclassified to revenues		(117.2	)		26.6			(90.6	)		425.2			(94.8	)		330.4
Other comprehensive income (loss)		(77.6	)		17.6			(60.0	)		288.5			(64.3	)		224.2
Comprehensive income (loss)								1,161.7									1,359.7
Less: Comprehensive income (loss) attributable to noncontrolling interests								175.4									258.0
Comprehensive income (loss) attributable to Targa Resources Corp.							$	986.3								$	1,101.7

See notes to consolidated financial statements.

6

TARGA RESOURCES CORP.

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			Owners’			Preferred
	Shares			Amount		Capital		Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)
Balance, June 30, 2023		224,052		$	0.2	$	3,045.8	$	199.5		$	130.8			15,160	$	(701.1	)	$	1,865.0		$	4,540.2		$	—
Compensation on equity grants		—			—		15.7		—			—			—		—			—			15.7			—
Dividend equivalent rights		—			—		—		(0.9	)		—			—		—			—			(0.9	)		—
Shares issued under compensation program		876			—		—		—			—			—		—			—			—			—
Shares tendered for tax withholding obligations		(263	)		—		—		—			—			263		(21.6	)		—			(21.6	)		—
Repurchases of common stock		(1,584	)		—		—		—			—			1,584		(132.0	)		—			(132.0	)		—
Excise tax on repurchases of common stock		—			—		—		—			—			—		(1.1	)		—			(1.1	)		—
Common stock dividends
Dividends - $0.50 per share		—			—		—		(113.1	)		—			—		—			—			(113.1	)		—
Distributions to noncontrolling interests		—			—		—		—			—			—		—			(56.5	)		(56.5	)		—
Contributions from noncontrolling interests		—			—		—		—			—			—		—			4.2			4.2			—
Other comprehensive income (loss)		—			—		—		—			(136.1	)		—		—			—			(136.1	)		—
Net income (loss)		—			—		—		220.0			—			—		—			59.0			279.0			—
Balance, September 30, 2023		223,081		$	0.2	$	3,061.5	$	305.5		$	(5.3	)		17,007	$	(855.8	)	$	1,871.7		$	4,377.8		$	—

See notes to consolidated financial statements.

7

TARGA RESOURCES CORP.

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			Owners’			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)
Balance, June 30, 2022		227,062		$	0.2	$	3,834.4		$	(1,137.9	)	$	(276.4	)		10,142	$	(350.4	)	$	2,331.0		$	4,400.9		$	—
Compensation on equity grants		—			—		14.4			—			—			—		—			—			14.4			—
Dividend equivalent rights		—			—		(1.7	)		—			—			—		—			—			(1.7	)		—
Shares issued under compensation program		481			—		—			—			—			—		—			—			—			—
Shares tendered for tax withholding obligations		(128	)		—		—			—			—			128		(8.6	)		—			(8.6	)		—
Repurchases of common stock		(1,157	)		—		—			—			—			1,157		(73.0	)		—			(73.0	)		—
Common stock dividends
Dividends - $0.35 per share		—			—		—			(79.3	)		—			—		—			—			(79.3	)		—
Dividends in excess of retained earnings		—			—		(79.3	)		79.3			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(75.2	)		(75.2	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			4.9			4.9			—
Other comprehensive income (loss)		—			—		—			—			269.7			—		—			—			269.7			—
Net income (loss)		—			—		—			193.1			—			—		—			86.2			279.3			—
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		$	—

See notes to consolidated financial statements.

8

TARGA RESOURCES CORP.

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			Owners’			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)
Balance, December 31, 2022		226,042		$	0.2	$	3,702.3		$	(626.8	)	$	54.7			11,897	$	(464.7	)	$	2,316.5		$	4,982.2		$	—
Compensation on equity grants		—			—		45.7			—			—			—		—			—			45.7			—
Dividend equivalent rights		—			—		(2.3	)		(0.9	)		—			—		—			—			(3.2	)		—
Shares issued under compensation program		2,149			—		—			—			—			—		—			—			—			—
Shares tendered for tax withholding obligations		(714	)		—		—			—			—			714		(55.4	)		—			(55.4	)		—
Repurchases of common stock		(4,396	)		—		—			—			—			4,396		(333.1	)		—			(333.1	)		—
Excise tax on repurchases of common stock		—			—		—			—			—			—		(2.6	)		—			(2.6	)		—
Common stock dividends
Dividends - $1.35 per share		—			—		—			(306.6	)		—			—		—			—			(306.6	)		—
Dividends in excess of retained earnings		—			—		(193.5	)		193.5			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(170.0	)		(170.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			7.1			7.1			—
Repurchase of noncontrolling interests, net of tax		—			—		(490.7	)		—			—			—		—			(457.3	)		(948.0	)		—
Other comprehensive income (loss)		—			—		—			—			(60.0	)		—		—			—			(60.0	)		—
Net income (loss)		—			—		—			1,046.3			—			—		—			175.4			1,221.7			—
Balance, September 30, 2023		223,081		$	0.2	$	3,061.5		$	305.5		$	(5.3	)		17,007	$	(855.8	)	$	1,871.7		$	4,377.8		$	—

See notes to consolidated financial statements.

9

TARGA RESOURCES CORP.

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			Owners’			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(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		—			—		41.8			—			—			—		—			—			41.8			—
Dividend equivalent rights		—			—		(5.2	)		—			—			—		—			—			(5.2	)		—
Shares issued under compensation program		1,580			—		—			—			—			—		—			—			—			—
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 - $47.50 per share		—			—		—			(30.0	)		—			—		—			—			(30.0	)		—
Dividends in excess of retained earnings		—			—		(30.0	)		30.0			—			—		—			—			—			—
Deemed dividends - repurchase of Series A Preferred Stock		—			—		(215.5	)		—			—			—		—			—			(215.5	)		—
Common stock dividends
Dividends - $1.05 per share		—			—		—			(239.1	)		—			—		—			—			(239.1	)		—
Dividends in excess of retained earnings		—			—		(239.1	)		239.1			—			—		—			—			—			—
Repurchase of Series A Preferred Stock		—			—		—			—			—			—		—			—			—			(749.7	)
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(234.0	)		(234.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			13.9			13.9			—
Repurchase of noncontrolling interests, net of tax		—			—		(53.1	)		—			—			—		—			(857.9	)		(911.0	)		—
Other comprehensive income (loss)		—			—		—			—			224.2			—		—			—			224.2			—
Net income (loss)		—			—		—			877.5			—			—		—			258.0			1,135.5			—
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		$	—

See notes to consolidated financial statements.

10

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2023			2022
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	1,221.7		$	1,135.5
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		9.8			7.2
Compensation on equity grants		45.7			41.8
Depreciation and amortization expense		988.2			766.2
(Gain) loss on sale or disposition of assets		(3.9	)		(8.1	)
Write-downs of assets		6.0			3.7
Accretion of asset retirement obligations		4.5			3.5
Deferred income tax expense (benefit)		252.1			116.4
Equity (earnings) loss of unconsolidated affiliates		(6.2	)		(8.7	)
Distributions of earnings received from unconsolidated affiliates		9.6			11.0
Risk management activities		(294.3	)		295.0
(Gain) loss from financing activities		—			49.6
(Gain) loss from sale of equity method investment		—			(435.9	)
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets		197.2			79.4
Inventories		(134.1	)		(320.5	)
Accounts payable, accrued liabilities and other liabilities		30.6			144.8
Interest payable		(73.0	)		(37.6	)
Net cash provided by operating activities		2,253.9			1,843.3
Cash flows from investing activities
Outlays for property, plant and equipment		(1,665.4	)		(815.4	)
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		2.9			18.3
Investments in unconsolidated affiliates		(14.9	)		(1.5	)
Proceeds from sale of equity method investment		—			857.0
Return of capital from unconsolidated affiliates		4.5			12.5
Other, net		(0.9	)		—
Net cash provided by (used in) investing activities		(1,673.8	)		(3,647.6	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		—			5,305.0
Repayments of credit facilities		(290.0	)		(4,755.0	)
Proceeds from borrowings of commercial paper notes		47,077.8			8,584.8
Repayments of commercial paper notes		(46,936.5	)		(7,952.8	)
Proceeds from borrowings under term loan facility		—			1,500.0
Proceeds from borrowings under accounts receivable securitization facility		103.1			1,180.0
Repayments of accounts receivable securitization facility		(343.1	)		(580.0	)
Proceeds from issuance of senior notes		1,717.0			2,741.4
Redemption of senior notes		—			(1,473.2	)
Principal payments of finance leases		(31.3	)		(10.8	)
Costs incurred in connection with financing arrangements		(5.0	)		(44.4	)
Repurchase of shares		(388.5	)		(227.9	)
Contributions from noncontrolling interests		7.1			13.9
Distributions to noncontrolling interests		(163.5	)		(252.0	)
Repurchase of noncontrolling interests		(1,091.9	)		(926.3	)
Redemption of Series A Preferred Stock		—			(965.2	)
Dividends paid to common and Series A Preferred shareholders		(314.8	)		(298.8	)
Net cash provided by (used in) financing activities		(659.6	)		1,838.7
Net change in cash and cash equivalents		(79.5	)		34.4
Cash and cash equivalents, beginning of period		219.0			158.5
Cash and cash equivalents, end of period	$	139.5		$	192.9

See notes to consolidated financial statements.

11

TARGA RESOURCES CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Note 1 — Organization and Operations

Our Organization

Targa Resources 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 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,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. 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”. Targa consolidated the Partnership and its subsidiaries under GAAP, and prepared the accompanying consolidated financial statements under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of 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”) prior to full redemption in May 2022; and

•the impacts of TRGP’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.

See Note 16 – 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, 2023 are not necessarily indicative of the results that may be expected for the year ending December 31, 2023.

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Note 3 — Significant Accounting Policies

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, 2023.

Recently Adopted Accounting Pronouncements

Supplier Finance Programs

In September 2022, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual and interim disclosure of the key terms of outstanding supplier finance programs and 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 are effective for fiscal years beginning after December 15, 2023. We maintain a supply chain finance program that allows participating suppliers to request early payment from a third-party financial institution of invoices that we confirm as valid. Under this program, we make payments in full to the third-party financial institution for the prior month’s outstanding balance within 15 days. The outstanding balance at the end of each reporting period is included in Accounts payable on our Consolidated Balance Sheets. We adopted the amendments on January 1, 2023, with no material impact on our consolidated financial statements.

Note 4 – Acquisitions and Divestitures

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 a 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 owned a 75% interest in the Permian region to Mont Belvieu segment of Grand Prix through Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) (prior to the Grand Prix Transaction, as defined below), a 100% interest in Train 6 and a 25% equity interest in GCX (prior to the sale of Targa GCX Pipeline LLC in February 2022 to a third party, with payment received in full in May 2022). The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $53.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture (the “Grand Prix Transaction”) for aggregate consideration of $1.05 billion in cash and a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of the interest in Grand Prix. 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 $490.7 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 Grand Prix Transaction resulted in a $457.3 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

Delaware Basin Acquisition

In July 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”). We received a final net working capital adjustment payment of approximately $11.4 million in the fourth quarter of 2022.

13

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 as if the Delaware Basin Acquisition had occurred on January 1, 2021. The 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 period presented, nor is it necessarily indicative of future results.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2022		2022
Revenues	$	5,391.1	$	16,604.0
Net income (loss)		288.3		1,089.7

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

•Reflects depreciation and amortization based on the fair 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 income for the three and nine months ended September 30, 2022;

•Excludes the impact of operations previously sold by Lucid, prior to Targa’s acquisition of Lucid;

•Excludes the 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 above pro forma adjustments.

Note 5 — Property, Plant and Equipment and Intangible Assets

	September 30, 2023			December 31, 2022			Estimated Useful Lives (In Years)
Gathering systems	$	10,698.4		$	10,403.1		5 to 20
Processing and fractionation facilities		7,783.4			7,421.2		5 to 25
Terminaling and storage facilities		1,369.2			1,341.6		5 to 25
Transportation assets		3,238.7			2,919.3		10 to 50
Other property, plant and equipment		404.8			387.6		3 to 50
Land		178.8			163.3		—
Construction in progress		1,566.3			1,011.0		—
Finance lease right-of-use assets		334.6			266.1		5 to 14
Property, plant and equipment		25,574.2			23,913.2
Accumulated depreciation, amortization and impairment		(10,240.7	)		(9,698.6	)
Property, plant and equipment, net	$	15,333.5		$	14,214.6
Intangible assets		4,378.0			4,379.7		10 to 20
Accumulated amortization and impairment		(1,931.4	)		(1,645.1	)
Intangible assets, net	$	2,446.6		$	2,734.6

During the three and nine months ended September 30, 2023, depreciation expense was $235.3 million and $700.2 million, respectively.

During the three and nine months ended September 30, 2022, depreciation expense was $206.5 million and $629.5 million, respectively.

14

Intangible Assets

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

During the three and nine months ended September 30, 2023, amortization expense was $96.0 million and $288.0 million, respectively.

During the three and nine months ended September 30, 2022, amortization expense was $80.7 million and $136.7 million, respectively.

The estimated annual amortization expense for intangible assets is approximately $384.0 million, $373.2 million, $326.0 million, $279.8 million and $252.2 million for each of the years 2023 through 2027, respectively.

Note 6 — Debt Obligations

	September 30, 2023			December 31, 2022
Current:
Partnership accounts receivable securitization facility, due August 2024 (1)	$	560.0		$	800.0
Finance lease liabilities		42.0			34.3
Current debt obligations		602.0			834.3
Long-term:
Term loan facility, variable rate, due July 2025		1,500.0			1,500.0
TRGP senior revolving credit facility, variable rate, due February 2027 (2)		1,150.0			1,298.7
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027		750.0			750.0
4.200% fixed rate, due February 2033		750.0			750.0
6.125% fixed rate, due March 2033		900.0			—
4.950% fixed rate, due April 2052		750.0			750.0
6.250% fixed rate, due July 2052		500.0			500.0
6.500% fixed rate, due February 2053		850.0			—
Unamortized discount		(40.5	)		(8.4	)
Senior unsecured notes issued by the Partnership: (3)
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
		12,143.9			10,574.7
Debt issuance costs, net of amortization		(63.9	)		(65.6	)
Finance lease liabilities		238.4			193.0
Long-term debt		12,318.4			10,702.1
Total debt obligations	$	12,920.4		$	11,536.4
Irrevocable standby letters of credit: (2)
Letters of credit outstanding under the TRGP senior revolving credit facility	$	22.3		$	33.2

(1)In August 2023, the Partnership amended its accounts receivable securitization facility (the “Securitization Facility”) to decrease the size of the Securitization Facility from $800.0 million to $600.0 million and to extend the termination date of the Securitization Facility to August 29, 2024. As of September 30, 2023, the Partnership had $560.0 million of qualifying receivables under the Securitization Facility, resulting in $40.0 million availability.

(2)We maintain 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 $2.75 billion TRGP senior revolving credit facility (the “TRGP Revolver”) equal to the aggregate amount outstanding under the Commercial Paper Program. As of September 30, 2023, the TRGP Revolver had no borrowings outstanding and the Commercial Paper Program had $1,150.0 million borrowings outstanding, resulting in approximately $1.6 billion of available liquidity, after accounting for outstanding letters of credit.

(3)We guarantee all of the Partnership’s outstanding senior unsecured notes.

15

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, 2023:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRGP Revolver and Commercial Paper Program	5.2% - 6.2%	5.8%
Securitization Facility	5.2% - 6.3%	5.7%
Term Loan Facility	5.8% - 6.8%	6.4%

Compliance with Debt Covenants

As of September 30, 2023, we were in compliance with the covenants contained in our various debt agreements.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of September 30, 2023, $5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

Debt Obligations

Commercial Paper Program

In 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 Issuances

In January 2023, we completed an underwritten public offering of (i) $900.0 million aggregate principal amount of our 6.125% Senior Notes due 2033 (the “6.125% Notes”) and (ii) $850.0 million aggregate principal amount of our 6.500% Senior Notes due 2053 (the “6.500% Notes”), resulting in net proceeds of approximately $1.7 billion. The 6.125% Notes and the 6.500% 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 6.125% Notes and the 6.500% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Fifth Supplemental Indenture, dated as of January 3, 2023, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

In the future, we or the Partnership may redeem, purchase or 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.

Note 7 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following:

	September 30, 2023		December 31, 2022
Deferred revenue	$	202.1	$	198.8
Asset retirement obligations		104.7		97.9
Operating lease liabilities		35.5		28.6
Other liabilities		15.9		15.9
Total other long-term liabilities	$	358.2	$	341.2

16

Deferred Revenue

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, 2023 and December 31, 2022, was $202.1 million and $198.8 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. See Note 12 – Contingencies.

Deferred revenue 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. Deferred revenue also includes contributions in aid of construction received from customers for which revenue is recognized over the expected contract term.

Note 8 — Common Stock and Related Matters

Common Share Repurchase Program

In October 2020, our Board of Directors approved a share repurchase program (the “2020 Share Repurchase Program”) for the repurchase of up to $500.0 million of our outstanding common stock. In May 2023, our Board of Directors approved a new share repurchase program (the “2023 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. During the second quarter of 2023, we exhausted the 2020 Share Repurchase Program. As of September 30, 2023, there was $810.7 million remaining under the 2023 Share Repurchase Program. We may discontinue the 2023 Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

For the three and nine months ended September 30, 2023, we repurchased 1,583,317 shares and 4,395,519 shares of our common stock at a weighted average per share price of $83.38 and $75.77 for a total net cost of $132.0 million and $333.1 million, respectively. For the three and nine months ended September 30, 2022, we repurchased 1,156,832 shares and 3,016,556 shares of our common stock at a weighted average per share price of $63.06 and $65.23 for a total net cost of $72.9 million and $196.8 million, respectively.

Common Stock Dividends

In April 2023, we declared an increase to our common dividend to $0.50 per common share or $2.00 per common share annualized effective for the first quarter of 2023.

The following table details the dividends declared and/or paid by us to common shareholders for the nine months ended September 30, 2023:

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Dividends on Share-Based Awards			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
September 30, 2023	November 15, 2023	$		113.0	$		111.5	$		1.5	$		0.50000
June 30, 2023	August 15, 2023			113.6			111.8			1.8			0.50000
March 31, 2023	May 15, 2023			114.7			113.0			1.7			0.50000
December 31, 2022	February 15, 2023			80.5			79.3			1.2			0.35000

17

Note 9 — Earnings per Common Share

In March 2023, the Compensation Committee amended the Restricted Stock Units Grant Agreements that govern the Restricted Stock Unit awards (“RSUs”) that vest no later than three years following the RSUs’ grant date. The amendment resulted in quarterly cash dividend payments to RSU holders beginning with the common stock dividend paid in May 2023. As the amended RSUs and certain four-year retention awards participate in nonforfeitable dividends with the common equity owners of the Company, they are considered participating securities.

We calculate earnings per share using the two-class method. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings.

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,
	2023		2022		2023		2022
	(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.	$	220.0	$	193.1	$	1,046.3	$	877.5
Less: Premium on repurchase of noncontrolling interests, net of tax (1)		—		—		490.7		53.1
Less: Dividends on Series A Preferred Stock (2)		—		—		—		30.0
Less: Deemed dividends on Series A Preferred (2)		—		—		—		215.5
Net income (loss) attributable to common shareholders		220.0		193.1		555.6		578.9
Less: Participating share-based earnings (3)		2.2		—		5.1		—
Net income (loss) allocated to common shareholders for basic earnings per share	$	217.8	$	193.1	$	550.5	$	578.9
Weighted average shares outstanding - basic		223.8		226.6		225.2		227.6
Dilutive effect of unvested stock awards		1.3		3.7		1.3		3.9
Weighted average shares outstanding - diluted		225.1		230.3		226.5		231.5
Net income (loss) available per common share - basic	$	0.97	$	0.85	$	2.44	$	2.54
Net income (loss) available per common share - diluted	$	0.97	$	0.84	$	2.43	$	2.50

(1)Represents premium paid on the Grand Prix Transaction and the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures.

(2)The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5% premium to the liquidation preference subsequent to March 16, 2022. In May 2022, we redeemed all of our issued and outstanding Series A Preferred.

(3)Represents the distributed and undistributed earnings of the Company attributable to the participating securities. The dilutive effect of the reallocation of participating securities to diluted net income attributable to common shareholders was immaterial.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Unvested restricted stock awards		1.4		—		1.6		—
Series A Preferred (1)		—		—		—		19.9

(1)The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5% premium to the liquidation preference subsequent to March 16, 2022. In May 2022, we redeemed all of our issued and outstanding Series A Preferred.

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Note 10 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have 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, 2023, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2023		2024		2025		2026		2027
Natural Gas	Swaps	MMBtu/d		148,830		103,512		56,856		10,373		—
Natural Gas	Basis Swaps	MMBtu/d		735,435		402,780		256,658		102,500		25,000
NGL	Swaps	Bbl/d		42,072		28,492		18,759		2,646		—
NGL	Futures	Bbl/d		34,467		18,549		4,562		—		—
Condensate	Swaps	Bbl/d		6,379		4,531		3,245		494		—

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, 2023					Fair Value as of December 31, 2022
	Balance Sheet	Derivative		Derivative			Derivative		Derivative
	Location	Assets		Liabilities			Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	61.8	$	(74.4	)	$	158.7	$	(93.8	)
	Long-term		12.6		(19.0	)		24.2		(30.9	)
Total derivatives designated as hedging instruments		$	74.4	$	(93.4	)	$	182.9	$	(124.7	)
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	22.4	$	(31.4	)	$	21.2	$	(226.3	)
	Long-term		5.1		(15.8	)		0.3		(109.2	)
Total derivatives not designated as hedging instruments		$	27.5	$	(47.2	)	$	21.5	$	(335.5	)
Total current position		$	84.2	$	(105.8	)	$	179.9	$	(320.1	)
Total long-term position			17.7		(34.8	)		24.5		(140.1	)
Total derivatives		$	101.9	$	(140.6	)	$	204.4	$	(460.2	)

19

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, 2023		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	83.2	$	(105.3	)	$	20.7	$	25.6	$	(27.0	)
	Counterparties without offsetting positions - assets		1.0		—			—		1.0		—
	Counterparties without offsetting positions - liabilities		—		(0.5	)		—		—		(0.5	)
			84.2		(105.8	)		20.7		26.6		(27.5	)
Long-Term Position
	Counterparties with offsetting positions or collateral		17.7		(34.8	)		2.3		2.1		(16.9	)
	Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		—			—		—		—
			17.7		(34.8	)		2.3		2.1		(16.9	)
Total Derivatives
	Counterparties with offsetting positions or collateral		100.9		(140.1	)		23.0		27.7		(43.9	)
	Counterparties without offsetting positions - assets		1.0		—			—		1.0		—
	Counterparties without offsetting positions - liabilities		—		(0.5	)		—		—		(0.5	)
		$	101.9	$	(140.6	)	$	23.0	$	28.7	$	(44.4	)
		Gross Presentation							Pro Forma Net Presentation
December 31, 2022		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	162.2	$	(316.7	)	$	12.2	$	27.2	$	(169.5	)
	Counterparties without offsetting positions - assets		17.7		—			—		17.7		—
	Counterparties without offsetting positions - liabilities		—		(3.4	)		—		—		(3.4	)
			179.9		(320.1	)		12.2		44.9		(172.9	)
Long-Term Position
	Counterparties with offsetting positions or collateral		24.5		(137.4	)		22.4		7.3		(97.8	)
	Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		(2.7	)		—		—		(2.7	)
			24.5		(140.1	)		22.4		7.3		(100.5	)
Total Derivatives
	Counterparties with offsetting positions or collateral		186.7		(454.1	)		34.6		34.5		(267.3	)
	Counterparties without offsetting positions - assets		17.7		—			—		17.7		—
	Counterparties without offsetting positions - liabilities		—		(6.1	)		—		—		(6.1	)
		$	204.4	$	(460.2	)	$	34.6	$	52.2	$	(273.4	)

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 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, 2023, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $43.9 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 Investors Service, Inc. and Standard & Poor’s Financial Services LLC, as defined in our ISDAs, we estimate that as of September 30, 2023, we would not be required to post 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 $38.7 million as of September 30, 2023. 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	2023			2022		2023		2022
Commodity contracts	$	(153.8	)	$	225.4	$	39.6	$	(136.7	)

20

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended September 30,					Nine Months Ended September 30,
Location of Gain (Loss)	2023		2022			2023		2022
Revenues	$	22.2	$	(121.7	)	$	117.2	$	(425.2	)

Based on valuations as of September 30, 2023, we expect to reclassify commodity hedge-related deferred losses of $(14.3) million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2026, with $(7.8) million of losses to be reclassified over the next twelve months.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial assets and liabilities (“financial instruments”) can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three months ended September 30, 2023, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward prices, as compared to our positions. For the nine months ended September 30, 2023, the unrealized mark-to-market gains are primarily attributable to favorable 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	2023			2022			2023		2022
Commodity contracts	Revenue	$	(7.0	)	$	(121.5	)	$	316.2	$	(317.5	)

See Note 11 – Fair Value Measurements and Note 16 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Note 11 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for 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, 2023, a net liability position of $38.7 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $195.7 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 asset of $118.2 million.

21

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.

Fair Value Hierarchy

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

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

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

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

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

	September 30, 2023
	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)	$	100.9	$	100.9	$	—	$	100.9	$	—
Liabilities from commodity derivative contracts (1)		139.6		139.6		—		139.3		0.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		139.5		139.5		—		—		—
TRGP Revolver and Commercial Paper Program		1,150.0		1,150.0		—		1,150.0		—
TRGP Senior unsecured notes		4,459.5		4,064.5		—		4,064.5		—
Term Loan Facility		1,500.0		1,500.0		—		1,500.0		—
Partnership’s Senior unsecured notes		5,034.4		4,672.7		—		4,672.7		—
Securitization Facility		560.0		560.0		—		560.0		—

	December 31, 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)	$	201.6	$	201.6	$	—	$	201.6	$	—
Liabilities from commodity derivative contracts (1)		457.4		457.4		—		457.4		—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		219.0		219.0		—		—		—
TRGP Revolver and Commercial Paper Program		1,298.7		1,298.7		—		1,298.7		—
TRGP Senior unsecured notes		2,741.6		2,452.6		—		2,452.6		—
Term Loan Facility		1,500.0		1,500.0		—		1,500.0		—
Partnership’s Senior unsecured notes		5,034.4		4,711.3		—		4,711.3		—
Securitization Facility		800.0		800.0		—		800.0		—

(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 10 – 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.

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

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

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

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the commodity forward curve where prices are not observable was immaterial. As of September 30, 2023, we had two derivative 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:

	Commodity
	Derivative Contracts
	Asset/(Liability)
Balance, December 31, 2022	$	—
New Level 3 derivative instruments		(0.3	)
Balance, September 30, 2023	$	(0.3	)

Note 12 — Contingencies

Legal Proceedings

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.

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 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.

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 in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. 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 filed a petition for review with the Supreme Court of Texas which was denied on October 20, 2023, but we are seeking rehearing and the appeal remains pending. The cumulative amount of interest on the award through September 30, 2023, if accrued, would have been approximately $52.3 million.

23

On July 24, 2023, we received a Notice of Violation from the New Mexico Environment Department, Air Quality Bureau, relating to alleged air permit violations between August 1, 2021 and June 30, 2022 by Lucid Energy Delaware, LLC, an entity we subsequently acquired in July 2022 in the Delaware Basin Acquisition and whose assets are now integrated into Targa Northern Delaware LLC, a wholly-owned subsidiary of the Company. We have been engaging with the New Mexico Environment Department to resolve this matter. Although this matter is ongoing and management cannot predict its ultimate outcome, the resolution of this matter may result in a fine or penalty in excess of $0.3 million. We do not expect that any expenditures related to this matter will be material to our consolidated financial statements.

On October 26, 2023, we received a final judgment in a lawsuit alleging a breach of contract related to the major winter storm in February 2021. The damages awarded against us are approximately $6.9 million, not including pre-judgment interest.

We are also a defendant in three other breach of contract cases related to force majeure events arising during the major winter storm in February 2021. We believe that the likelihood of a partial loss could be reasonably possible, and, while it is not possible to predict the ultimate outcome of these cases on an individual or consolidated basis, we estimate that the total range of potential loss resulting from all of these cases could be between $0 and $10.0 million in the aggregate. We intend to continue to vigorously defend these cases.

Note 13 — 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 16 years.

	2023		2024		2025 and after
Fixed consideration to be recognized as of September 30, 2023	$	109.7	$	461.6	$	2,407.5

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 16 – Segment Information.

Note 14 — Income Taxes

We record income taxes using an estimated annual effective tax rate and recognize specific events discretely as they occur. Our effective tax rate for the three and nine months ended September 30, 2023 is lower than the U.S. corporate statutory rate of 21% primarily due to the release of a portion of our state valuation allowances, stock compensation windfall and income allocated to noncontrolling interests that is not taxable to the Company. Our effective tax rate for the three and nine months ended September 30, 2022 was lower than the U.S. corporate statutory rate of 21% primarily due to the release of a portion of our federal valuation allowances in addition to income allocated to noncontrolling interests that is not taxable to the Company.

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, 2023, our valuation allowance was $9.4 million, a decrease of $27.5 million from December 31, 2022. After the change in valuation allowance, we have a net deferred tax liability of $418.3 million.

We are subject to tax in the U.S. and various state jurisdictions. Additionally, we are subject to periodic audits and reviews by U.S. federal and state taxing authorities. As of September 30, 2023, Internal Revenue Service (“IRS”) examinations are currently in process for the 2019, 2020 and 2021 taxable years of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We are not aware of any potential audit findings that would give rise to adjustments to taxable income and do not anticipate material changes related to these audits.

24

Note 15 — Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2023		2022
Cash:
Interest paid, net of capitalized interest (1)	$	574.1	$	332.6
Income taxes (received) paid, net		9.5		1.1
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net	$	76.8	$	(40.1	)
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests	$	6.5	$	(18.0	)

(1)Interest capitalized on major projects was $29.2 million and $9.5 million for the nine months ended September 30, 2023 and 2022.

Note 16 — Segment Information

We operate in two 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 Grand Prix, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. The associated assets 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, 2023
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	231.3	$	3,176.5	$	(33.5	)	$	—		$	3,374.3
Fees from midstream services		337.4		184.9		—			—			522.3
		568.7		3,361.4		(33.5	)		—			3,896.6
Intersegment revenues
Sales of commodities		1,298.8		49.0		—			(1,347.8	)		—
Fees from midstream services		0.6		11.5		—			(12.1	)		—
		1,299.4		60.5		—			(1,359.9	)		—
Revenues	$	1,868.1	$	3,421.9	$	(33.5	)	$	(1,359.9	)	$	3,896.6
Operating margin (1)	$	505.0	$	457.4	$	(33.5	)
Other financial information:
Total assets (2)	$	12,405.7	$	7,568.0	$	7.8		$	208.1		$	20,189.6
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	421.5	$	229.7	$	—		$	3.8		$	655.0

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	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)	$	12,119.0	$	7,074.9	$	1.5		$	194.5		$	19,389.9
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	222.0	$	139.1	$	—		$	8.0		$	369.1

	Nine Months Ended September 30, 2023
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	787.1	$	9,232.6	$	294.3	$	—		$	10,314.0
Fees from midstream services		979.7		527.1		—		—			1,506.8
		1,766.8		9,759.7		294.3		—			11,820.8
Intersegment revenues
Sales of commodities		3,621.8		210.2		—		(3,832.0	)		—
Fees from midstream services		1.7		32.9		—		(34.6	)		—
		3,623.5		243.1		—		(3,866.6	)		—
Revenues	$	5,390.3	$	10,002.8	$	294.3	$	(3,866.6	)	$	11,820.8
Operating margin (1)	$	1,545.9	$	1,394.4	$	294.3
Other financial information:
Total assets (2)	$	12,405.7	$	7,568.0	$	7.8	$	208.1		$	20,189.6
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	1,081.7	$	645.0	$	—	$	15.5		$	1,742.2

	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)	$	12,119.0	$	7,074.9	$	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.

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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,
	2023			2022			2023		2022
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	606.0		$	1,748.1		$	1,835.9	$	4,244.1
NGL		2,635.4			3,145.4			7,651.6		11,048.3
Condensate and crude oil		117.7			150.0			393.1		441.0
		3,359.1			5,043.5			9,880.6		15,733.4
Non-customer revenue:
Derivative activities - Hedge		22.2			(121.7	)		117.2		(425.2	)
Derivative activities - Non-hedge (1)		(7.0	)		(121.5	)		316.2		(317.5	)
		15.2			(243.2	)		433.4		(742.7	)
Total sales of commodities		3,374.3			4,800.3			10,314.0		14,990.7
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		333.3			376.4			966.3		829.6
NGL transportation, fractionation and services		71.1			82.3			190.5		215.1
Storage, terminaling and export		102.2			82.5			302.3		285.3
Other		15.7			18.6			47.7		54.3
Total fees from midstream services		522.3			559.8			1,506.8		1,384.3
Total revenues	$	3,896.6		$	5,360.1		$	11,820.8	$	16,375.0

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	505.0		$	564.6		$	1,545.9		$	1,437.0
Logistics and Transportation operating margin		457.4			340.2			1,394.4			1,014.6
Other operating margin		(33.5	)		(112.2	)		294.3			(294.9	)
Depreciation and amortization expense		(331.3	)		(287.2	)		(988.2	)		(766.2	)
General and administrative expense		(90.0	)		(79.1	)		(253.4	)		(217.2	)
Other operating income (expense)		(2.5	)		3.8			(2.0	)		4.4
Interest expense, net		(175.1	)		(125.8	)		(509.8	)		(300.5	)
Equity earnings (loss)		3.0			1.7			6.2			8.7
Gain (loss) from financing activities		—			—			—			(49.6	)
Gain (loss) from sale of equity method investment		—			—			—			435.9
Other, net		(0.1	)		(14.7	)		(5.0	)		(14.7	)
Income (loss) before income taxes	$	332.9		$	291.3		$	1,482.4		$	1,257.5

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2022 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

Overview

Targa Resources 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.

Our Operations

We are engaged primarily 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.

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 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 facilities in Mont Belvieu, Texas. Our Downstream facilities 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.

Recent Developments

In response to increasing production and to meet the infrastructure needs of producers and our downstream customers, our major expansion projects include the following:

Permian Midland Processing Expansions

•In February 2022, 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 commenced operations late in the first quarter of 2023.

•In August 2022, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Greenwood plant”). The Greenwood plant commenced operations in the fourth quarter of 2023.

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•In August 2023, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Greenwood II plant”). The Greenwood II plant is expected to begin operations in the fourth quarter of 2024.

Permian Delaware Processing Expansions

•In February 2022, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Midway plant”). The Midway plant commenced operations in the second quarter of 2023 and we subsequently idled an existing 165 MMcf/d cryogenic natural gas processing plant in the third quarter of 2023.

•In November 2022, 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 February 2023, we announced the transfer of an existing cryogenic natural gas processing plant acquired in the purchase of Southcross Energy Operating LLC and its subsidiaries to the Permian Delaware. The plant will be installed as a new 230 MMcf/d cryogenic natural gas processing plant (the “Roadrunner II plant”). The Roadrunner II plant is expected to begin operations in the second quarter of 2024.

•In August 2023, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose plant”). The Bull Moose plant is expected to begin operations in the second quarter of 2025.

Fractionation Expansion

•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 January 2023, we reached an agreement with our partners in Gulf Coast Fractionators (“GCF”) to reactivate GCF’s 135 MBbl/d fractionation facility. The facility is expected to be operational late in the first quarter of 2024.

•In May 2023, we announced plans to construct a new 120 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 10”). Train 10 is expected to begin operations in the first quarter of 2025.

NGL Pipeline Expansion

•In November 2022, we announced plans to construct a new NGL pipeline (the “Daytona NGL Pipeline”) as an addition to our common carrier Grand Prix system. The pipeline will transport NGLs from the Permian Basin and connect to the 30-inch diameter segment of Grand Prix in North Texas, where volumes will be transported to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. The Daytona NGL Pipeline is expected to be in service by the end of 2024.

Acquisitions

In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture (the “Grand Prix Transaction”) for approximately $1.05 billion in cash and paid a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of Grand Prix, including the Daytona NGL Pipeline. For further details on our acquisitions and divestitures, see Note 4 - Acquisitions and Divestitures to our Consolidated Financial Statements.

Capital Allocation

In April 2023, we declared an increase to our common dividend to $0.50 per common share or $2.00 per common share annualized effective for the first quarter of 2023.

For the three and nine months ended September 30, 2023, we repurchased 1,583,317 shares and 4,395,519 shares of our common stock at a weighted average per share price of $83.38 and $75.77 for a total net cost of $132.0 million and $333.1 million, respectively.

In October 2020, our Board of Directors approved a share repurchase program (the “2020 Share Repurchase Program”) for the repurchase of up to $500.0 million of our outstanding common stock. In May 2023, our Board of Directors authorized a new $1.0 billion common share repurchase program (the “2023 Share Repurchase Program” and, together with the 2020 Share Repurchase Program, the “Share Repurchase Programs”). The amount authorized under the 2023 Share Repurchase Program was in addition to the amount remaining under the 2020 Share Repurchase Program. During the second quarter of 2023, we exhausted the 2020 Share Repurchase

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Program. There was $810.7 million remaining under the 2023 Share Repurchase Program as of September 30, 2023. We may discontinue the 2023 Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

Financing Activities

In January 2023, we completed an underwritten public offering of (i) $900.0 million in aggregate principal amount of our 6.125% Senior Notes due 2033 (the “6.125% Notes”) and (ii) $850.0 million in aggregate principal amount of our 6.500% Senior Notes due 2053 (the “6.500% Notes”), resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net proceeds for general corporate purposes, including to reduce borrowings under our $2.75 billion TRGP senior revolving credit facility (the “TRGP Revolver”) and our unsecured commercial paper note program (the “Commercial Paper Program”).

In August 2023, the Partnership amended its accounts receivable securitization facility (the “Securitization Facility”) to decrease the size of the Securitization Facility from $800.0 million to $600.0 million and to extend the termination date of the Securitization Facility to August 29, 2024.

For additional information about our recent debt-related transactions, see Note 6 - Debt Obligations to our Consolidated Financial Statements.

Corporation Tax Matters

As of September 30, 2023, Internal Revenue Service (“IRS”) examinations are currently in process for the 2019, 2020 and 2021 taxable years of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S federal income tax purposes. We are responding to the information requests from the IRS with respect to these audits. We are not aware of any potential audit findings that would give rise to adjustments to taxable income and do not anticipate material changes related to these audits.

On August 16, 2022, President Biden signed into law the IRA which, among other things, introduced a corporate alternative minimum tax (the “CAMT”), imposed a 1% excise tax on stock buybacks, and provided tax incentives to promote clean energy. 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 prior to such taxable year exceeds $1.0 billion. The 1% excise tax on stock buybacks is accrued in the current year for payment with the first quarterly excise tax return of the subsequent year.

On December 27, 2022, IRS Notice 2023-7 (the “Notice”) was issued by the U.S. Department of the Treasury and the IRS. The Notice provides guidance on the application of the CAMT which may be relied upon until final regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance, and a number of operational, economic, accounting and regulatory assumptions, including the safe harbor provided for in the Notice, the Company does not qualify as an “applicable corporation” for 2023.

Recent Accounting Pronouncements

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

How We Evaluate Our Operations

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.

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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 facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment).

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, 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

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 inflation, and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

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.

Non-GAAP Measures

We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP

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measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to 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 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.

Adjusted Operating Margin

We define adjusted 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 adjusted operating margin consists primarily of:

•service fees related to natural gas and crude oil gathering, treating and processing; and

•revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements.

Logistics and Transportation adjusted operating margin consists primarily of:

•service fees (including the pass-through of energy costs included in certain fee rates);

•system product gains and losses; and

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

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

Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:

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

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

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

Management reviews adjusted 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.”

Adjusted EBITDA

We define adjusted EBITDA as Net income (loss) attributable to 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.

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Distributable Cash Flow and Adjusted Free Cash Flow

We define distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). 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.

Our Non-GAAP Financial Measures

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	220.0		$	193.1		$	1,046.3		$	877.5
Interest (income) expense, net		175.1			125.8			509.8			300.5
Income tax expense (benefit)		53.9			12.0			260.7			122.0
Depreciation and amortization expense		331.3			287.2			988.2			766.2
(Gain) loss on sale or disposition of assets		(0.9	)		(6.5	)		(3.9	)		(8.1	)
Write-down of assets		3.4			2.7			6.0			3.7
(Gain) loss from financing activities (1)		—			—			—			49.6
(Gain) loss from sale of equity method investment		—			—			—			(435.9	)
Transaction costs related to business acquisition (2)		—			20.3			—			20.3
Equity (earnings) loss		(3.0	)		(1.7	)		(6.2	)		(8.7	)
Distributions from unconsolidated affiliates and preferred partner interests, net		5.3			2.4			14.1			21.7
Compensation on equity grants		15.7			14.4			45.7			41.8
Risk management activities		33.5			112.2			(294.3	)		295.0
Noncontrolling interests adjustments (3)		(1.0	)		6.7			(3.2	)		15.2
Litigation expense (4)		6.9			—			6.9			—
Adjusted EBITDA	$	840.2		$	768.6		$	2,570.1		$	2,060.8
Interest expense on debt obligations (5)		(172.1	)		(123.0	)		(500.9	)		(305.2	)
Maintenance capital expenditures, net (6)		(65.0	)		(49.4	)		(153.0	)		(126.8	)
Cash taxes		(0.9	)		(1.3	)		(8.6	)		(5.6	)
Distributable Cash Flow	$	602.2		$	594.9		$	1,907.6		$	1,623.2
Growth capital expenditures, net (6)		(593.6	)		(304.1	)		(1,588.5	)		(624.8	)
Adjusted Free Cash Flow	$	8.6		$	290.8		$	319.1		$	998.4

(1)Gains or losses on debt repurchases or early debt extinguishments.

(2)Includes financial advisory, legal and other professional fees, and other one-time transaction costs.

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

(4)Litigation expense includes charges related to litigation resulting from the major winter storm in February 2021 that we consider outside the ordinary course of our business and/or not reflective of our ongoing core operations. We may incur such charges from time to time, and we believe it is useful to exclude such charges because we do not consider them reflective of our ongoing core operations and because of the generally singular nature of the claims underlying such litigation.

(5)Excludes amortization of debt issuance costs.

(6)Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.

33

Consolidated Results of Operations

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

	Three Months Ended September 30,												Nine Months Ended September 30,
	2023			2022			2023 vs. 2022						2023			2022			2023 vs. 2022
	(In millions)
Revenues:
Sales of commodities	$	3,374.3		$	4,800.3		$	(1,426.0	)		(30	%)	$	10,314.0		$	14,990.7		$	(4,676.7	)		(31	%)
Fees from midstream services		522.3			559.8			(37.5	)		(7	%)		1,506.8			1,384.3			122.5			9	%
Total revenues		3,896.6			5,360.1			(1,463.5	)		(27	%)		11,820.8			16,375.0			(4,554.2	)		(28	%)
Product purchases and fuel		2,690.0			4,306.3			(1,616.3	)		(38	%)		7,777.9			13,557.8			(5,779.9	)		(43	%)
Operating expenses		277.7			261.3			16.4			6	%		808.4			660.6			147.8			22	%
Depreciation and amortization expense		331.3			287.2			44.1			15	%		988.2			766.2			222.0			29	%
General and administrative expense		90.0			79.1			10.9			14	%		253.4			217.2			36.2			17	%
Other operating (income) expense		2.5			(3.8	)		6.3			166	%		2.0			(4.4	)		6.4			145	%
Income (loss) from operations		505.1			430.0			75.1			17	%		1,990.9			1,177.6			813.3			69	%
Interest expense, net		(175.1	)		(125.8	)		(49.3	)		39	%		(509.8	)		(300.5	)		(209.3	)		70	%
Equity earnings (loss)		3.0			1.7			1.3			76	%		6.2			8.7			(2.5	)		(29	%)
Gain (loss) from financing activities		—			—			—			—			—			(49.6	)		49.6			100	%
Gain (loss) from sale of equity method investment		—			—			—			—			—			435.9			(435.9	)		(100	%)
Other, net		(0.1	)		(14.6	)		14.5			99	%		(4.9	)		(14.6	)		9.7			66	%
Income tax (expense) benefit		(53.9	)		(12.0	)		(41.9	)	NM				(260.7	)		(122.0	)		(138.7	)		114	%
Net income (loss)		279.0			279.3			(0.3	)		—			1,221.7			1,135.5			86.2			8	%
Less: Net income (loss) attributable to noncontrolling interests		59.0			86.2			(27.2	)		(32	%)		175.4			258.0			(82.6	)		(32	%)
Net income (loss) attributable to Targa Resources Corp.		220.0			193.1			26.9			14	%		1,046.3			877.5			168.8			19	%
Premium on repurchase of noncontrolling interests, net of tax		—			—			—			—			490.7			53.1			437.6		NM
Dividends on Series A Preferred Stock		—			—			—			—			—			30.0			(30.0	)		(100	%)
Deemed dividends on Series A Preferred Stock		—			—			—			—			—			215.5			(215.5	)		(100	%)
Net income (loss) attributable to common shareholders	$	220.0		$	193.1		$	26.9			14	%	$	555.6		$	578.9		$	(23.3	)		(4	%)
Financial data:
Adjusted EBITDA (1)	$	840.2		$	768.6		$	71.6			9	%	$	2,570.1		$	2,060.8		$	509.3			25	%
Distributable cash flow (1)		602.2			594.9			7.3			1	%		1,907.6			1,623.2			284.4			18	%
Adjusted free cash flow (1)		8.6			290.8			(282.2	)		(97	%)		319.1			998.4			(679.3	)		(68	%)

(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.

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022

The decrease in commodity sales reflects lower natural gas, NGL and condensate prices ($2,704.1 million), partially offset by higher NGL and natural gas volumes ($1,000.1 million) and the favorable impact of hedges ($258.5 million).

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

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

The increase in operating expenses is primarily due to higher labor and maintenance costs due to increased activity and system expansions, the acquisition of certain assets in the Delaware Basin 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 impact of system expansions on our asset base, partially offset by the shortening of the depreciable lives of certain assets that were idled in 2022.

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

34

The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.

The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to our joint venture partner in WestTX.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($7,920.7 million), partially offset by higher NGL, natural gas and condensate volumes ($2,063.8 million) and the favorable impact of hedges ($1,176.2 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 South Texas, and higher export fees, partially offset by lower transportation and fractionation fees.

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

The increase in operating expenses is primarily due to higher labor and maintenance costs due to increased activity and 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 impact of system expansions on our asset base, partially offset by the shortening of depreciable lives of certain assets that were idled in 2022.

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 due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.

During 2022, we terminated the previous TRGP senior secured revolving credit facility and the Partnership’s senior secured revolving credit facility. In addition, the Partnership redeemed its 5.375% Senior Notes due 2027 and its 5.875% Senior Notes due 2026. These transactions resulted in a net loss from financing activities.

During 2022, we completed the sale of Targa GCX Pipeline LLC to a third party (the “GCX Sale”) resulting in a gain from sale of an equity method investment.

The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to our joint venture partner in WestTX and Venice Energy Services Company, L.L.C.

The premium on repurchase of noncontrolling interests, net of tax is due to the Grand Prix Transaction in 2023 and the purchase of all of Stonepeak Infrastructure Partners’ interests in our development company joint ventures in 2022.

The decrease in dividends on Series A Preferred Stock (“Series A Preferred”) is due to the full redemption of all of our issued and outstanding shares of Series A Preferred in May 2022.

35

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

	Gathering and Processing		Logistics and Transportation		Other
	(In millions)
Three Months Ended:
September 30, 2023	$	505.0	$	457.4	$	(33.5	)
September 30, 2022		564.6		340.2		(112.2	)
Nine Months Ended:
September 30, 2023	$	1,545.9	$	1,394.4	$	294.3
September 30, 2022		1,437.0		1,014.6		(294.9	)

36

Gathering and Processing Segment

	Three Months Ended September 30,										Nine Months Ended September 30,
	2023			2022		2023 vs. 2022					2023		2022		2023 vs. 2022
		(In millions, except operating statistics and price amounts)
Operating margin	$		505.0	$	564.6	$	(59.6	)	(11	%)	$	1,545.9	$	1,437.0	$	108.9		8	%
Operating expenses			189.6		176.6		13.0		7	%		560.8		434.5		126.3		29	%
Adjusted operating margin	$		694.6	$	741.2	$	(46.6	)	(6	%)	$	2,106.7	$	1,871.5	$	235.2		13	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			2,566.9		2,307.2		259.7		11	%		2,474.1		2,172.3		301.8		14	%
Permian Delaware (5)			2,485.4		1,784.8		700.6		39	%		2,513.7		1,254.6		1,259.1		100	%
Total Permian			5,052.3		4,092.0		960.3		23	%		4,987.8		3,426.9		1,560.9		46	%
SouthTX (6)			394.4		335.5		58.9		18	%		373.9		256.9		117.0		46	%
North Texas			212.0		177.7		34.3		19	%		205.2		176.1		29.1		17	%
SouthOK (6)			394.6		400.4		(5.8	)	(1	%)		391.2		422.7		(31.5	)	(7	%)
WestOK			206.2		212.8		(6.6	)	(3	%)		207.1		209.1		(2.0	)	(1	%)
Total Central			1,207.2		1,126.4		80.8		7	%		1,177.4		1,064.8		112.6		11	%
Badlands (6) (7)			128.3		144.8		(16.5	)	(11	%)		129.6		133.1		(3.5	)	(3	%)
Total Field			6,387.8		5,363.2		1,024.6		19	%		6,294.8		4,624.8		1,670.0		36	%
Coastal			535.6		539.1		(3.5	)	(1	%)		532.4		564.7		(32.3	)	(6	%)
Total			6,923.4		5,902.3		1,021.1		17	%		6,827.2		5,189.5		1,637.7		32	%
NGL production, MBbl/d (3)
Permian Midland (4)			373.1		332.6		40.5		12	%		357.4		314.8		42.6		14	%
Permian Delaware (5)			322.5		210.9		111.6		53	%		325.3		159.1		166.2		104	%
Total Permian			695.6		543.5		152.1		28	%		682.7		473.9