[10-Q] Targa Resources Corp. Quarterly Earnings Report

Rhea-AI Filing Summary

WFCF Q2-25 snapshot: Revenue inched up 2.6% YoY to $6.6 m, aided by an 18% rise in tag sales, while verification revenue was flat and professional services fell 18%. Inflation in labor and product costs squeezed gross margin to 38.4% (42.3%), pushing operating income down 5.8% to $0.5 m. A $0.17 m unrealised Bitcoin gain plus steady dividends lifted net income 14.9% to $0.6 m, or $0.11 basic/diluted EPS (vs $0.09).

1H-25 trends: Revenue dipped 1.2% to $11.8 m and net income fell 11% to $0.6 m as margins narrowed 250 bp. Operating cash flow remained strong at $1.8 m, funding $0.6 m of share repurchases and modest $0.06 m capex. Cash climbed to $3.2 m (from $2.0 m YE-24); the balance sheet stays debt-free with equity of $10.0 m.

Balance-sheet & events: Deferred revenue rose 36% to $2.4 m, pointing to future service delivery. In April 1.24 m treasury shares were retired, reducing stated capital. On 22 Jul 25 WFCF agreed to sell its 10% stake in Progressive Beef for ~$1.8 m cash plus 12,585 WFCF shares, bolstering liquidity. Management notes ongoing cattle-cycle contraction and normal seasonality heading into H2.

Positive

• EPS up 22% YoY to $0.11 despite margin pressure, aided by other income.
• Cash balance rose 59% to $3.2 m, with no debt outstanding.
• Deferred revenue up 36% to $2.4 m, indicating future service demand.
• Progressive Beef stake sale to add ~$1.8 m cash post-quarter, strengthening liquidity.

Negative

• Gross margin fell 390 bp YoY due to higher labor and product costs.
• Operating income down 18% YTD; core profitability weakening.
• Professional services revenue declined 18% in Q2, reducing segment diversity.
• Line of credit not renewed, removing an external liquidity source (though unused).

Insights

Equity Research Analyst

TL;DR: Modest top-line growth, margin pressure, solid cash; overall neutral impact.

Quarterly revenue beat inflation but margin erosion trimmed operating profit. EPS expansion was driven by non-core Bitcoin gains and dividends, not core operations. Cash generation and a debt-free balance sheet provide cushion, and the Progressive Beef exit will inject an extra $1.8 m. However, YTD sales and operating income are down, and seasonality plus cattle-cycle contraction could restrain H2. Net effect is balanced—no game-changing catalysts, but fundamentals remain intact.

Agrifood Industry Specialist

TL;DR: Product-tag sales up; verification flat—reflects cattle-cycle headwinds.

Verification demand mirrors U.S. herd contraction, limiting growth. Tag revenue strength shows producers still value WFCF’s traceability offering. Deferred revenue build suggests forthcoming audit activity once herd conditions stabilise. The Progressive Beef divestiture reduces exposure to a cyclical partner while freeing cash. Long-term thesis—growing need for transparency—remains, but near-term outlook hinges on weather-driven herd rebuilding.

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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 June 30, 2025

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 July 31, 2025, there were 215,191,852 shares of the registrant’s common stock, $0.001 par value, outstanding.

Total number of pages (excluding Exhibits): 49

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements		4
Consolidated Balance Sheets as of June 30, 2025 and December 31, 2024		4
Consolidated Statements of Operations for the three and six months ended June 30, 2025 and 2024		5
Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2025 and 2024		6
Consolidated Statements of Cash Flows for the six months ended June 30, 2025 and 2024		7
Consolidated Statements of Changes in Owners’ Equity for the three and six months ended June 30, 2025 and 2024		8
Notes to Consolidated Financial Statements		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		42
Item 4. Controls and Procedures		44
PART II—OTHER INFORMATION
Item 1. Legal Proceedings		46
Item 1A. Risk Factors		46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 3. Defaults Upon Senior Securities		46
Item 4. Mine Safety Disclosures		46
Item 5. Other Information		46
Item 6. Exhibits		46
SIGNATURES
Signatures		48

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;

•actions taken by other countries with significant hydrocarbon production;

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

•the timing and success of business development efforts;

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

•industry changes, including the impact of consolidation, changes in competition and any increase in the use of alternative forms of energy for oil, gas and NGLs;

•downside commodity price volatility from a variety of potential factors that can result in lower activity in our areas of operation;

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

•general economic, market and business conditions;

•the potential impact of significant public health crises and their impact on demand for oil, gas and NGLs;

•weather and other natural phenomena, and related impacts;

•our ability to access the capital markets on favorable terms, or at all, which will depend on general market conditions, including the impact of interest rates and any associated Federal Reserve policies and disruptions in the bank and capital markets as a whole, our credit ratings and leverage levels, and demand for our common equity, senior unsecured notes and commercial paper;

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

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

•changes in laws and regulations, particularly with regard to taxes, tariffs and international trade, safety and the protection of the environment; and

•the risks described in our annual report on Form 10-K for the year ended December 31, 2024 (“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 June 30, 2025 (“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
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
STACK		Sooner Trend, Anadarko, Canadian and Kingfisher

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

	June 30, 2025				December 31, 2024
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	113.1			$	157.3
Trade receivables, net of allowances of $0.7 million and $2.5 million as of June 30, 2025 and December 31, 2024		1,408.6				1,618.3
Inventories		443.5				334.3
Assets from risk management activities		78.3				61.8
Other current assets		163.7				124.6
Total current assets		2,207.2				2,296.3
Property, plant and equipment, net		19,020.3				18,062.7
Intangible assets, net		1,814.4				1,977.4
Long-term assets from risk management activities		26.2				25.3
Investments in unconsolidated affiliates		268.6				193.3
Other long-term assets		176.1				179.1
Total assets	$	23,512.8			$	22,734.1
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	1,726.7			$	2,012.5
Accrued liabilities		214.0				336.0
Interest payable		313.2				269.1
Liabilities from risk management activities		154.6				167.3
Current debt obligations		768.2				387.7
Total current liabilities		3,176.7				3,172.6
Long-term debt		16,082.3				13,786.9
Long-term liabilities from risk management activities		72.7				92.0
Deferred income taxes, net		1,079.4				872.1
Other long-term liabilities		390.3				392.3
Contingencies (see Note 12)
Owners’ equity:
Targa Resources Corp. stockholders’ equity:
Common Stock ($0.001 par value, 450,000,000 shares authorized as of June 30, 2025 and December 31, 2024)		0.2				0.2
Issued Outstanding
June 30, 2025 242,332,690 215,509,429
December 31, 2024 241,764,105 217,763,821
Additional paid-in capital		3,053.3				3,089.1
Retained earnings (deficit)		1,705.4				1,190.0
Accumulated other comprehensive income (loss)		43.2				27.5
Treasury stock, at cost (26,823,261 shares and 24,000,284 shares as of June 30, 2025 and December 31, 2024)		(2,214.0	)			(1,714.4	)
Total Targa Resources Corp. stockholders’ equity		2,588.1				2,592.4
Noncontrolling interests		123.3				1,825.8
Total owners’ equity		2,711.4				4,418.2
Total liabilities and owners’ equity	$	23,512.8			$	22,734.1

See notes to consolidated financial statements.

4

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,								Six Months Ended June 30,
	2025				2024				2025				2024
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Sales of commodities	$	3,636.3			$	2,966.7			$	7,520.7			$	6,909.3
Fees from midstream services		623.8				595.3				1,300.9				1,215.1
Total revenues		4,260.1				3,562.0				8,821.6				8,124.4
Costs and expenses:
Product purchases and fuel		2,436.0				2,197.4				5,693.8				5,415.4
Operating expenses		323.6				290.7				627.2				568.7
Depreciation and amortization expense		373.7				348.6				741.3				689.1
General and administrative expense		95.0				98.3				189.5				184.8
Other operating (income) expense		(1.8	)			(0.2	)			(7.1	)			(0.3	)
Income (loss) from operations		1,033.6				627.2				1,576.9				1,266.7
Other income (expense):
Interest expense, net		(218.4	)			(176.0	)			(415.5	)			(404.6	)
Equity earnings (loss)		5.1				2.9				10.6				5.6
Other, net		1.0				(0.9	)			1.3				1.0
Income (loss) before income taxes		821.3				453.2				1,173.3				868.7
Income tax (expense) benefit		(184.1	)			(94.3	)			(256.3	)			(177.1	)
Net income (loss)		637.2				358.9				917.0				691.6
Less: Net income (loss) attributable to noncontrolling interests		8.1				60.4				17.4				117.9
Net income (loss) attributable to Targa Resources Corp.		629.1				298.5				899.6				573.7
Premium on repurchase of noncontrolling interests, net of tax		—				—				70.5				—
Net income (loss) attributable to common shareholders	$	629.1			$	298.5			$	829.1			$	573.7
Net income (loss) per common share - basic	$	2.88			$	1.34			$	3.79			$	2.56
Net income (loss) per common share - diluted	$	2.87			$	1.33			$	3.78			$	2.55
Weighted average shares outstanding - basic		216.6				221.0				217.2				221.9
Weighted average shares outstanding - diluted		217.3				221.9				218.0				222.9

See notes to consolidated financial statements.

5

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

		Three Months Ended June 30,
		2025												2024
		Pre-Tax				Related Income Tax				After Tax				Pre-Tax				Related Income Tax				After Tax
		(Unaudited)
		(In millions)
Net income (loss)										$	637.2											$	358.9
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		$	75.8			$	(17.3	)			58.5			$	3.0			$	(0.7	)			2.3
Settlements reclassified to revenues			(27.7	)			6.3				(21.4	)			(32.2	)			7.4				(24.8	)
Other comprehensive income (loss)			48.1				(11.0	)			37.1				(29.2	)			6.7				(22.5	)
Comprehensive income (loss)											674.3												336.4
Less: Comprehensive income (loss) attributable to noncontrolling interests											8.1												60.4
Comprehensive income (loss) attributable to Targa Resources Corp.										$	666.2											$	276.0

		Six Months Ended June 30,
		2025												2024
		Pre-Tax				Related Income Tax				After Tax				Pre-Tax				Related Income Tax				After Tax
		(Unaudited)
		(In millions)
Net income (loss)										$	917.0											$	691.6
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		$	42.0			$	(9.6	)			32.4			$	(67.2	)		$	15.4				(51.8	)
Settlements reclassified to revenues			(21.6	)			4.9				(16.7	)			(29.0	)			6.6				(22.4	)
Other comprehensive income (loss)			20.4				(4.7	)			15.7				(96.2	)			22.0				(74.2	)
Comprehensive income (loss)											932.7												617.4
Less: Comprehensive income (loss) attributable to noncontrolling interests											17.4												117.9
Comprehensive income (loss) attributable to Targa Resources Corp.										$	915.3											$	499.5

See notes to consolidated financial statements.

6

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Six Months Ended June 30,
		2025				2024
		(Unaudited)
		(In millions)
Cash flows from operating activities
Net income (loss)		$	917.0			$	691.6
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Amortization in interest expense			7.9				7.2
Compensation on equity grants			34.7				29.7
Depreciation and amortization expense			741.3				689.1
Deferred income tax expense (benefit)			226.7				170.8
Equity (earnings) loss of unconsolidated affiliates			(10.6	)			(5.6	)
Distributions of earnings received from unconsolidated affiliates			7.4				11.2
Risk management activities			(31.7	)			68.8
Other, net			14.0				6.4
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets			319.8				302.9
Inventories			(105.4	)			60.2
Accounts payable, accrued liabilities and other liabilities			(352.5	)			(269.7	)
Interest payable			44.1				18.3
Net cash provided by (used in) operating activities			1,812.7				1,780.9
Cash flows from investing activities
Outlays for property, plant and equipment			(1,698.3	)			(1,410.1	)
Investments in unconsolidated affiliates			(75.8	)			(20.1	)
Return of capital from unconsolidated affiliates			3.7				1.0
Other, net			0.3				1.5
Net cash provided by (used in) investing activities			(1,770.1	)			(1,427.7	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings of commercial paper notes			46,656.2				36,477.0
Repayments of commercial paper notes			(47,119.7	)			(35,349.0	)
Repayment of term loan facility			—				(500.0	)
Proceeds from borrowings under accounts receivable securitization facility			870.0				125.0
Repayments of accounts receivable securitization facility			(1,200.0	)			(150.0	)
Proceeds from issuance of senior unsecured notes			3,490.7				—
Principal payments of finance leases			(30.2	)			(23.2	)
Costs incurred in connection with financing arrangements			(41.3	)			—
Repurchases of common stock			(449.2	)			(478.8	)
Shares tendered for tax withholding obligations			(46.7	)			(36.7	)
Contributions from noncontrolling interests			—				6.0
Distributions to noncontrolling interests			(24.2	)			(113.3	)
Repurchase of noncontrolling interests			(1,800.4	)			(1.3	)
Dividends paid to common shareholders			(385.6	)			(284.2	)
Other, net			(6.4	)			—
Net cash provided by (used in) financing activities			(86.8	)			(328.5	)
Net change in cash and cash equivalents			(44.2	)			24.7
Cash and cash equivalents, beginning of period			157.3				141.7
Cash and cash equivalents, end of period		$	113.1			$	166.4

See notes to consolidated financial statements.

7

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY

											Retained			Accumulated
								Additional			Earnings			Other			Treasury									Total
		Common Stock						Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owners’
		Shares			Amount			Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity
		(Unaudited)
		(In millions, except shares in thousands)
Balance, March 31, 2025			217,461		$	0.2		$	3,036.2		$	1,295.3		$	6.1			24,867		$	(1,886.3	)	$	121.2		$	2,572.7
Compensation on equity grants			—			—			17.1			—			—			—			—			—			17.1
Dividend equivalent rights			—			—			—			(0.7	)		—			—			—			—			(0.7	)
Shares issued under compensation program			4			—			—			—			—			—			—			—			—
Shares tendered for tax withholding obligations			(1	)		—			—			—			—			1			(0.2	)		—			(0.2	)
Repurchases of common stock			(1,955	)		—			—			—			—			1,955			(324.3	)		—			(324.3	)
Excise tax on repurchases of common stock			—			—			—			—			—			—			(3.2	)		—			(3.2	)
Common stock dividends
Dividends - $1.00 per share			—			—			—			(218.3	)		—			—			—			—			(218.3	)
Distributions to noncontrolling interests			—			—			—			—			—			—			—			(6.0	)		(6.0	)
Other comprehensive income (loss)			—			—			—			—			37.1			—			—			—			37.1
Net income (loss)			—			—			—			629.1			—			—			—			8.1			637.2
Balance, June 30, 2025			215,509		$	0.2		$	3,053.3		$	1,705.4		$	43.2			26,823		$	(2,214.0	)	$	123.3		$	2,711.4

											Retained			Accumulated
								Additional			Earnings			Other			Treasury									Total
		Common Stock						Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owners’
		Shares			Amount			Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity
		(Unaudited)
		(In millions, except shares in thousands)
Balance, March 31, 2024			222,150		$	0.2		$	3,073.4		$	654.1		$	33.9			19,110		$	(1,057.7	)	$	1,873.7		$	4,577.6
Compensation on equity grants			—			—			15.1			—			—			—			—			—			15.1
Dividend equivalent rights			—			—			—			(1.1	)		—			—			—			—			(1.1	)
Shares issued under compensation program			7			—			—			—			—			—			—			—			—
Shares tendered for tax withholding obligations			(1	)		—			—			—			—			1			(0.2	)		—			(0.2	)
Repurchases of common stock			(2,986	)		—			—			—			—			2,986			(355.1	)		—			(355.1	)
Excise tax on repurchases of common stock			—			—			—			—			—			—			(3.5	)		—			(3.5	)
Common stock dividends
Dividends - $0.75 per share			—			—			—			(167.6	)		—			—			—			—			(167.6	)
Distributions to noncontrolling interests			—			—			—			—			—			—			—			(56.8	)		(56.8	)
Contributions from noncontrolling interests			—			—			—			—			—			—			—			4.2			4.2
Other comprehensive income (loss)			—			—			—			—			(22.5	)		—			—			—			(22.5	)
Net income (loss)			—			—			—			298.5			—			—			—			60.4			358.9
Balance, June 30, 2024			219,170		$	0.2		$	3,088.5		$	783.9		$	11.4			22,097		$	(1,416.5	)	$	1,881.5		$	4,349.0

See notes to consolidated financial statements.

8

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY

											Retained			Accumulated
								Additional			Earnings			Other			Treasury									Total
		Common Stock						Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owners’
		Shares			Amount			Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity
		(Unaudited)
		(In millions, except shares in thousands)
Balance, December 31, 2024			217,764		$	0.2		$	3,089.1		$	1,190.0		$	27.5			24,000		$	(1,714.4	)	$	1,825.8		$	4,418.2
Compensation on equity grants			—			—			34.7			—			—			—			—			—			34.7
Dividend equivalent rights			—			—			—			(1.4	)		—			—			—			—			(1.4	)
Shares issued under compensation program			568			—			—			—			—			—			—			—			—
Shares tendered for tax withholding obligations			(217	)		—			—			—			—			217			(46.7	)		—			(46.7	)
Repurchases of common stock			(2,606	)		—			—			—			—			2,606			(449.2	)		—			(449.2	)
Excise tax on repurchases of common stock			—			—			—			—			—			—			(3.7	)		—			(3.7	)
Common stock dividends
Dividends - $1.75 per share			—			—			—			(382.8	)		—			—			—			—			(382.8	)
Distributions to noncontrolling interests			—			—			—			—			—			—			—			(10.7	)		(10.7	)
Repurchase of noncontrolling interests, net of tax			—			—			(70.5	)		—			—			—			—			(1,709.2	)		(1,779.7	)
Other comprehensive income (loss)			—			—			—			—			15.7			—			—			—			15.7
Net income (loss)			—			—			—			899.6			—			—			—			17.4			917.0
Balance, June 30, 2025			215,509		$	0.2		$	3,053.3		$	1,705.4		$	43.2			26,823		$	(2,214.0	)	$	123.3		$	2,711.4

											Retained			Accumulated
								Additional			Earnings			Other			Treasury									Total
		Common Stock						Paid in			(Accumulated			Comprehensive			Shares						Noncontrolling			Owners’
		Shares			Amount			Capital			Deficit)			Income (Loss)			Shares			Amount			Interests			Equity
		(Unaudited)
		(In millions, except shares in thousands)
Balance, December 31, 2023			222,611		$	0.2		$	3,058.8		$	492.0		$	85.6			17,484		$	(896.9	)	$	1,870.3		$	4,610.0
Compensation on equity grants			—			—			29.7			—			—			—			—			—			29.7
Dividend equivalent rights			—			—			—			(1.8	)		—			—			—			—			(1.8	)
Shares issued under compensation program			1,172			—			—			—			—			—			—			—			—
Shares tendered for tax withholding obligations			(441	)		—			—			—			—			441			(36.7	)		—			(36.7	)
Repurchases of common stock			(4,172	)		—			—			—			—			4,172			(478.8	)		—			(478.8	)
Excise tax on repurchases of common stock			—			—			—			—			—			—			(4.1	)		—			(4.1	)
Common stock dividends
Dividends - $1.25 per share			—			—			—			(280.0	)		—			—			—			—			(280.0	)
Distributions to noncontrolling interests			—			—			—			—			—			—			—			(112.7	)		(112.7	)
Contributions from noncontrolling interests			—			—			—			—			—			—			—			6.0			6.0
Other comprehensive income (loss)			—			—			—			—			(74.2	)		—			—			—			(74.2	)
Net income (loss)			—			—			—			573.7			—			—			—			117.9			691.6
Balance, June 30, 2024			219,170		$	0.2		$	3,088.5		$	783.9		$	11.4			22,097		$	(1,416.5	)	$	1,881.5		$	4,349.0

See notes to consolidated financial statements.

9

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 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 consolidates the Partnership and its subsidiaries under GAAP, and the accompanying consolidated financial statements have been prepared 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;

•the inclusion of the TRGP senior unsecured notes;

•the inclusion of the TRGP commercial paper notes; 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 significant 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 six months ended June 30, 2025 are not necessarily indicative of the results that may be expected for the year ending December 31, 2025.

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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 six months ended June 30, 2025.

Recently issued accounting pronouncements not yet adopted

Improvements to Income Tax Disclosures

In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in this update require, among other items, that public entities disclose, on an annual basis, (i) specific categories of income taxes in the rate reconciliation, and (ii) a disaggregation of income taxes paid by federal, state, and foreign taxes.

These amendments are effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The amendments are required to be applied prospectively with retrospective application permitted. We are evaluating the effect of the amendments on our consolidated financial statements and expect to disclose the required information beginning in the annual report on Form 10-K for the year ended December 31, 2025. The impact of the adoption will be limited to disclosure in the notes to consolidated financial statements for annual reporting periods.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Comprehensive income (Topic 220): Disaggregation of Income Statement Expenses. The amendments in this update require, among other items, that public entities disclose, on an annual and interim basis, in tabular format in the footnotes to the financial statements, disaggregated information about specific categories underlying certain income statement expense line items that contain any of the following expense categories (i) purchases of inventory, (ii) employee compensation, (iii) depreciation, (iv) intangible asset amortization, and (v) depletion. Additionally, the amendments require disclosure of the total amount of selling expenses and an annual disclosure of the definition of selling expenses.

These amendments are effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The disclosures may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. We are evaluating the effect of the amendments on our consolidated financial statements and expect to disclose the required information for fiscal years beginning in the annual report on Form 10-K for the year ended December 31, 2027 and for interim periods beginning in the quarterly report on Form 10-Q for the quarter ended March 31, 2028. The impact of the adoption will be limited to disclosure in the notes to consolidated financial statements.

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Note 4 — Joint Ventures and Acquisitions

On March 5, 2025, we completed the acquisition of Blackstone’s 45% interest in Targa Badlands LLC (“Targa Badlands”) for aggregate consideration of $1.8 billion in cash, with an additional $0.4 million of capitalized transaction costs (the “Badlands Transaction”). As a result of the acquisition, we own 100% of the interests in and earnings of Targa Badlands effective January 1, 2025. The change in our ownership interest 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 $70.5 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.

Note 5 — Property, Plant and Equipment and Intangible Assets

		June 30, 2025				December 31, 2024				Estimated Useful Lives (In Years)
Gathering systems		$	11,845.5			$	11,575.0			5 to 20
Processing and fractionation facilities			10,037.1				9,543.3			5 to 25
Terminaling and storage facilities			1,550.0				1,469.1			5 to 25
Transportation assets			4,436.5				4,131.5			10 to 50
Other property, plant and equipment			572.8				537.7			3 to 25
Land			209.2				198.6			—
Construction in progress			2,003.1				1,702.9			—
Finance lease right-of-use assets			434.8				401.3			5 to 14
Property, plant and equipment			31,089.0				29,559.4
Accumulated depreciation, amortization and impairment			(12,068.7	)			(11,496.7	)
Property, plant and equipment, net		$	19,020.3			$	18,062.7
Intangible assets			4,378.0				4,378.0			10 to 20
Accumulated amortization and impairment			(2,563.6	)			(2,400.6	)
Intangible assets, net		$	1,814.4			$	1,977.4

During the three and six months ended June 30, 2025, depreciation expense was $292.2 million and $578.3 million, respectively. During the three and six months ended June 30, 2024, depreciation expense was $255.3 million and $502.5 million, respectively.

Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair values of these acquired intangible assets were determined at the dates 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 six months ended June 30, 2025, amortization expense was $81.5 million and $163.0 million, respectively. During the three and six months ended June 30, 2024, amortization expense was $93.3 million and $186.6 million, respectively.

The estimated annual amortization expense for intangible assets is approximately $326.0 million, $279.8 million, $252.2 million, $234.0 million and $214.1 million for each of the years 2025 through 2029, respectively.

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Note 6 – Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consist of the following:

Gathering and Processing Segment

•50% operated ownership interest in Little Missouri 4.

Logistics and Transportation Segment

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

•50% operated ownership interest in Cayenne Pipeline, LLC (“Cayenne”); and

•17.5% non-operated ownership interest in the Blackcomb and Traverse pipelines, which are currently under construction, held by a joint venture (“Blackcomb”).

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

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

		Balance at December 31, 2024				Equity Earnings (Loss)				Cash Distributions				Contributions (1)				Balance at June 30, 2025
Little Missouri 4		$	84.3			$	7.6			$	(9.7	)		$	5.1			$	87.3
GCF			66.4				0.2				—				0.9				67.5
Cayenne			12.3				3.0				(1.4	)			—				13.9
Blackcomb			30.3				(0.2	)			—				69.8				99.9
Total		$	193.3			$	10.6			$	(11.1	)		$	75.8			$	268.6

(1)Includes capitalized interest of $1.9 million related to our contributions to Blackcomb.

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Note 7 — Debt Obligations

		June 30, 2025				December 31, 2024
Current:
Partnership accounts receivable securitization facility, due August 2025 (1)		$	—			$	330.0
Senior unsecured notes issued by the Partnership: (2)
6.500% fixed rate, due July 2027 (3)			705.2				—
Debt issuance costs, net of amortization (3)			(1.9	)			—
Finance lease liabilities			64.9				57.7
Current debt obligations			768.2				387.7
Long-term:
TRGP senior revolving credit facility, variable rate, due February 2030 (4)			667.0				1,130.5
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027			750.0				750.0
6.150% fixed rate, due March 2029			1,000.0				1,000.0
4.900% fixed rate, due September 2030 (3)			750.0				—
4.200% fixed rate, due February 2033			750.0				750.0
6.125% fixed rate, due March 2033			900.0				900.0
6.500% fixed rate, due March 2034			1,000.0				1,000.0
5.500% fixed rate, due February 2035			1,000.0				1,000.0
5.550% fixed rate, due August 2035 (5)			1,000.0				—
5.650% fixed rate, due February 2036 (3)			750.0				—
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				850.0
6.125% fixed rate, due May 2055 (5)			1,000.0				—
Unamortized discount			(38.0	)			(29.4	)
Senior unsecured notes issued by the Partnership: (2)
6.500% fixed rate, due July 2027 (3)			—				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
			15,958.2				13,635.5
Debt issuance costs, net of amortization			(115.5	)			(89.0	)
Finance lease liabilities			239.6				240.4
Long-term debt			16,082.3				13,786.9
Total debt obligations		$	16,850.5			$	14,174.6
Irrevocable standby letters of credit: (4)
Letters of credit outstanding under the TRGP senior revolving credit facility		$	9.4			$	17.6

(1)As of June 30, 2025, the Partnership had no amount drawn under its $600.0 million accounts receivable securitization facility (the “Securitization Facility”), resulting in $600.0 million of remaining availability. In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.

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

(3)In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036, resulting in net proceeds of approximately $1.5 billion. The net proceeds were initially used to reduce borrowings under the Securitization Facility and Commercial Paper Program as reflected on the balance sheet as of June 30, 2025. A conditional notice of redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 was issued in June 2025, resulting in the classification of the notes within Current debt obligations on our Consolidated Balance Sheets as of June 30, 2025. In July 2025, we used borrowings under the Securitization Facility and Commercial Paper Program to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027.

(4)In February 2025, we entered into a new $3.5 billion TRGP senior revolving credit facility (the “TRGP Revolver”), which matures in February 2030. In connection with our entry into the TRGP Revolver, we terminated our previous TRGP senior revolving credit facility (the “Previous TRGP Revolver”). 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 the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program at any one time not to exceed $3.5 billion. The TRGP Revolver had no borrowings outstanding and the Commercial Paper Program had $667.0 million of borrowings outstanding, resulting in approximately $2.8 billion of available liquidity as of June 30, 2025, after accounting for outstanding letters of credit.

(5)In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055, resulting in net proceeds of approximately $2.0 billion.

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The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the six months ended June 30, 2025:

		Range of Interest Rates Incurred		Weighted Average Interest Rate Incurred
TRGP Revolver and Commercial Paper Program		4.6% - 4.8%		4.7%
Securitization Facility		5.2% - 5.3%		5.2%

Compliance with Debt Covenants

As of June 30, 2025, we were in compliance with the covenants contained in our various debt agreements.

TRGP Revolver

In February 2025, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent and Swing Line Lender, the letter of credit issuers party thereto and the other lenders party thereto. The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $150.0 million. We recorded $8.9 million of debt issuance costs related to the TRGP Revolver in Other long-term assets on our Consolidated Balance Sheets. The TRGP Revolver matures on February 18, 2030. We will be able to extend the maturity date, subject to the required lenders’ consent, by one year up to two times. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver. As a result of the termination of the Previous TRGP Revolver, we recorded a loss due to debt extinguishment of $0.6 million.

Senior Unsecured Notes Issuance

In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 (the “5.550% Notes due 2035”) and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055 (the “6.125% Notes due 2055”) (collectively, the “February 2025 Senior Unsecured Notes”), resulting in net proceeds of approximately $2.0 billion. The February 2025 Senior Unsecured 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 February 2025 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Tenth Supplemental Indenture, dated as of February 27, 2025, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $20.4 million and discount of $6.1 million as reductions to the carrying value of the February 2025 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. We used the net proceeds from the debt issuance to fund the Badlands Transaction and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 (the “4.900% Notes due 2030”) and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036 (the “5.650% Notes due 2036”) (collectively, the “June 2025 Senior Unsecured Notes”), resulting in net proceeds of approximately $1.5 billion. The June 2025 Senior Unsecured 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 June 2025 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Eleventh Supplemental Indenture, dated as of June 18, 2025, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $13.5 million and discount of $3.2 million as reductions to the carrying value of the June 2025 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. The net proceeds were initially used to reduce borrowings under the Securitization Facility and Commercial Paper Program as reflected on the balance sheet as of June 30, 2025. In July 2025, we used borrowings under the Securitization Facility and Commercial Paper Program to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 (the “6.500% Notes due 2027”).

Debt Extinguishment

A conditional notice of redemption of all of the 6.500% Notes due 2027 was issued in June 2025, with the redemption conditioned on completion of the June 2025 Senior Unsecured Notes issuance, resulting in the classification of the 6.500% Notes due 2027 within Current debt obligations on our Consolidated Balance Sheets as of June 30, 2025. In July 2025, we completed the redemption of all of the Partnership’s 6.500% Notes due 2027 and recorded a debt extinguishment loss of $1.9 million due to a write-off of debt issuance costs in the third quarter.

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Partnership’s Accounts Receivable Securitization Facility

In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.

Note 8 — Common Stock and Related Matters

Common Share Repurchase Program

In May 2023, our Board of Directors approved a share repurchase program (the “2023 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. During the first quarter of 2025, we exhausted the 2023 Share Repurchase Program.

In July 2024, our Board of Directors approved a share repurchase program (the “2024 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. In addition, in August 2025, our Board of Directors approved a new share repurchase program (the “2025 Share Repurchase Program” and, together with the 2024 Share Repurchase Program, the “Share Repurchase Programs”) for the repurchase of up to $1.0 billion of our outstanding common stock. We are not obligated to repurchase any specific dollar amount or number of shares under the Share Repurchase Programs and may discontinue these programs at any time.

For the three and six months ended June 30, 2025, we repurchased 1,955,099 shares and 2,606,262 shares of our common stock at a weighted average per share price of $165.86 and $172.35 for a total net cost of $324.3 million and $449.2 million, respectively. For the three and six months ended June 30, 2024, we repurchased 2,985,816 shares and 4,172,260 shares of our common stock at a weighted average per share price of $118.91 and $114.75 for a total net cost of $355.1 million and $478.8 million, respectively.

As of June 30, 2025, there was $566.2 million remaining under the 2024 Share Repurchase Program. The amount authorized under the 2025 Share Repurchase Program is in addition to the amount that remained under the 2024 Share Repurchase Program.

Common Stock Dividends

In April 2025, we declared an increase to our common dividend to $1.00 per common share, or $4.00 per common share annualized, effective for the first quarter of 2025.

The following table details the dividends declared and/or paid by us to common shareholders for the six months ended June 30, 2025:

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)
June 30, 2025		August 15, 2025		$	217.1			$	215.2			$	1.9			$	1.00000
March 31, 2025		May 15, 2025			219.0				216.9				2.1				1.00000
December 31, 2024		February 14, 2025			165.2				163.6				1.6				0.75000

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Note 9 — Earnings per Common Share

Restricted Stock Unit awards (“RSUs”) that vest no later than three years following the RSUs’ grant date participate in quarterly cash dividend payments. As these 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 June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
		(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.		$	629.1			$	298.5			$	899.6			$	573.7
Less: Premium on repurchase of noncontrolling interests, net of tax (1)			—				—				70.5				—
Net income (loss) attributable to common shareholders			629.1				298.5				829.1				573.7
Less: Participating share-based earnings (2)			4.0				2.3				5.2				4.5
Net income (loss) allocated to common shareholders for basic earnings per share		$	625.1			$	296.2			$	823.9			$	569.2
Weighted average shares outstanding - basic			216.6				221.0				217.2				221.9
Dilutive effect of unvested restricted stock awards			0.7				0.9				0.8				1.0
Weighted average shares outstanding - diluted			217.3				221.9				218.0				222.9
Net income (loss) available per common share - basic		$	2.88			$	1.34			$	3.79			$	2.56
Net income (loss) available per common share - diluted		$	2.87			$	1.33			$	3.78			$	2.55

(1)Represents premium paid on the Badlands Transaction. See Note 4 – Joint Ventures and Acquisitions.

(2)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 June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
Unvested restricted stock awards			1.1				1.2				1.1				1.2

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 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 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 in current earnings.

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At June 30, 2025, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2025			2026			2027			2028
Natural Gas	Swaps	MMBtu/d		81,584			81,604			44,508			11,047
Natural Gas	Basis Swaps	MMBtu/d		568,668			368,459			288,329			100,000
NGL	Swaps	Bbl/d		44,183			31,685			15,863			3,944
NGL	Futures	Bbl/d		35,793			4,726			—			—
Condensate	Swaps	Bbl/d		8,023			8,249			2,381			592

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. The master netting provisions reduced our maximum loss due to counterparty credit risk by $18.7 million as of June 30, 2025. The range of losses attributable to our individual counterparties would be between $0.3 million and $8.2 million, depending on the counterparty in default. 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 table reflects the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as of the periods presented:

				Fair Value as of June 30, 2025								Fair Value as of December 31, 2024
		Balance Sheet		Derivative				Derivative				Derivative				Derivative
		Location		Assets				Liabilities				Assets				Liabilities
Derivatives designated as hedging instruments
Commodity contracts		Current		$	67.0			$	(17.3	)		$	50.8			$	(29.0	)
		Long-term			16.4				(17.4	)			20.8				(11.7	)
Total derivatives designated as hedging instruments				$	83.4			$	(34.7	)		$	71.6			$	(40.7	)
Derivatives not designated as hedging instruments
Commodity contracts		Current		$	11.3			$	(137.3	)		$	11.0			$	(138.3	)
		Long-term			9.8				(55.3	)			4.5				(80.3	)
Total derivatives not designated as hedging instruments				$	21.1			$	(192.6	)		$	15.5			$	(218.6	)
Total current position				$	78.3			$	(154.6	)		$	61.8			$	(167.3	)
Total long-term position					26.2				(72.7	)			25.3				(92.0	)
Total derivatives				$	104.5			$	(227.3	)		$	87.1			$	(259.3	)

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The following tables reflect the pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis as of the periods presented:

			Gross Presentation												Pro Forma Net Presentation
June 30, 2025			Asset				Liability				Collateral				Asset				Liability
Current Position
	Counterparties with offsetting positions or collateral		$	75.7			$	(154.6	)		$	14.6			$	19.8			$	(84.1	)
	Counterparties without offsetting positions - assets			2.6				—				—				2.6				—
	Counterparties without offsetting positions - liabilities			—				—				—				—				—
				78.3				(154.6	)			14.6				22.4				(84.1	)
Long-Term Position
	Counterparties with offsetting positions or collateral			26.2				(70.7	)			(2.2	)			6.3				(53.0	)
	Counterparties without offsetting positions - assets			—				—				—				—				—
	Counterparties without offsetting positions - liabilities			—				(2.0	)			—				—				(2.0	)
				26.2				(72.7	)			(2.2	)			6.3				(55.0	)
Total Derivatives
	Counterparties with offsetting positions or collateral			101.9				(225.3	)			12.4				26.1				(137.1	)
	Counterparties without offsetting positions - assets			2.6				—				—				2.6				—
	Counterparties without offsetting positions - liabilities			—				(2.0	)			—				—				(2.0	)
			$	104.5			$	(227.3	)		$	12.4			$	28.7			$	(139.1	)
			Gross Presentation												Pro Forma Net Presentation
December 31, 2024			Asset				Liability				Collateral				Asset				Liability
Current Position
	Counterparties with offsetting positions or collateral		$	61.7			$	(167.3	)		$	37.1			$	9.2			$	(77.7	)
	Counterparties without offsetting positions - assets			0.1				—				—				0.1				—
	Counterparties without offsetting positions - liabilities			—				—				—				—				—
				61.8				(167.3	)			37.1				9.3				(77.7	)
Long-Term Position
	Counterparties with offsetting positions or collateral			24.2				(91.5	)			9.0				4.2				(62.5	)
	Counterparties without offsetting positions - assets			1.1				—				—				1.1				—
	Counterparties without offsetting positions - liabilities			—				(0.5	)			—				—				(0.5	)
				25.3				(92.0	)			9.0				5.3				(63.0	)
Total Derivatives
	Counterparties with offsetting positions or collateral			85.9				(258.8	)			46.1				13.4				(140.2	)
	Counterparties without offsetting positions - assets			1.2				—				—				1.2				—
	Counterparties without offsetting positions - liabilities			—				(0.5	)			—				—				(0.5	)
			$	87.1			$	(259.3	)		$	46.1			$	14.6			$	(140.7	)

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 included 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 agreements (“ISDAs”), which govern the key terms with our counterparties. Our ISDAs contain credit-risk related contingent features and are not secured. As of June 30, 2025, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $134.3 million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s Ratings and Standard & Poor’s Financial Services LLC, as defined in our ISDAs, we estimate that as of June 30, 2025, we would not be required to post collateral to any counterparty and that no counterparty could request immediate, full settlement 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 $122.8 million as of June 30, 2025. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for our 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 (loss) (“OCI”) and amounts reclassified from OCI to revenue:

		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow		Three Months Ended June 30,								Six Months Ended June 30,
Hedging Relationships		2025				2024				2025				2024
Commodity contracts		$	75.8			$	3.0			$	42.0			$	(67.2	)

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		Gain (Loss) Reclassified from OCI into Income (Effective Portion)
		Three Months Ended June 30,								Six Months Ended June 30,
Location of Gain (Loss)		2025				2024				2025				2024
Revenues		$	27.7			$	32.2			$	21.6			$	29.0

As of June 30, 2025, we expect to reclassify commodity hedge related net deferred gains of $49.5 million included in Accumulated OCI into earnings before income taxes over the next twelve months. However, actual amounts reclassified into earnings could be greater or less than the net amount reported in Accumulated OCI. As of June 30, 2025, the maximum length of time over which we have hedged our exposure to the variability in future cash flows is through 2028.

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 our Consolidated Balance Sheets and through earnings in our Consolidated Statements of Operations 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 June 30, 2025, we had net unrealized mark-to-market gains primarily driven by favorable movements in natural gas forward basis curves. For the six months ended June 30, 2025, we had net unrealized mark-to-market losses primarily driven by unfavorable movements in natural gas forward basis curves.

		Location of Gain (Loss)		Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated		Recognized in Income on		Three Months Ended June 30,								Six Months Ended June 30,
as Hedging Instruments		Derivatives		2025				2024				2025				2024
Commodity contracts		Revenue		$	206.2			$	(88.8	)		$	(79.0	)		$	(120.7	)

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 our 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 instruments 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 instruments we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The derivatives at June 30, 2025 represent a net liability position of $122.8 million and reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative instruments. 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 $298.5 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 $52.8 million.

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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. 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 current and long-term debt as follows:

•the TRGP Revolver, commercial paper notes and Securitization 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:

		June 30, 2025
		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)		$	103.6			$	103.6			$	—			$	103.6			$	—
Liabilities from commodity derivative contracts (1)			226.4				226.4				—				225.3				1.1
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			113.1				113.1				—				—				—
TRGP Revolver and Commercial Paper Program			667.0				667.0				—				667.0				—
TRGP Senior unsecured notes			10,962.0				11,004.7				—				11,004.7				—
Partnership’s Senior unsecured notes			5,034.4				4,986.5				—				4,986.5				—

		December 31, 2024
		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)		$	87.0			$	87.0			$	—			$	87.0			$	—
Liabilities from commodity derivative contracts (1)			259.2				259.2				—				259.2				—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			157.3				157.3				—				—				—
Previous TRGP Revolver and Commercial Paper Program			1,130.5				1,130.5				—				1,130.5				—
TRGP Senior unsecured notes			7,470.6				7,438.6				—				7,438.6				—
Partnership’s Senior unsecured notes			5,034.4				4,928.0				—				4,928.0				—
Securitization Facility			330.0				330.0				—				330.0				—

(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 report certain of our swaps at fair value using Level 3 inputs due to such derivative instruments not having observable market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments 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, which is based on observable or public data sources and extrapolated when observable prices are not available. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were the forward NGLs and natural gas pricing curves, for which a significant portion of the derivative instruments’ term is beyond available forward pricing.

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, 2024			$	—
Unrealized gain (loss) included in OCI				(1.1	)
Balance, June 30, 2025			$	(1.1	)

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 (the “EPA”), 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 July 24, 2023, we received a Notice of Violation (the “New Mexico NOV”) from the New Mexico Environment Department (the “NMED”), Air Quality Bureau, relating to alleged air permit violations at the Red Hills gas processing facility. The alleged air permit violations occurred primarily between August 1, 2021 and June 30, 2022, while the facility was owned by Lucid Energy Delaware, LLC (“Lucid”), a subsidiary we acquired in July 2022 and renamed Targa Northern Delaware LLC. On December 5, 2024, we received a proposed Administrative Compliance Order (the “ACO”) from the NMED relating to the violations identified in the New Mexico NOV and certain other alleged violations. The ACO includes a proposed civil penalty of approximately $47.8 million and requires certain capital improvements to address the operations and excess air emissions at the Red Hills processing facility. These capital improvements, totaling approximately $140 million, were substantially completed by December 31, 2024.

On January 3, 2025, we filed a Request for Hearing with the NMED with respect to the ACO. We have cooperated with the NMED in identifying and correcting legacy environmental issues since our acquisition of Lucid, and we expect to continue to engage with the NMED to resolve this matter. Although this matter is ongoing and we cannot predict its ultimate outcome, we believe we have valid defenses to many of the NMED allegations and intend to vigorously defend this matter.

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. Both parties are appealing the judgment. We were named as defendants in other breach of contract cases related to force majeure events arising during the major winter storm in February 2021. These cases were settled by the parties for an aggregate amount of approximately $12.7 million, not including pre-judgment interest.

In April 2024, we received an administrative Notice of Violation (the “EPA NOV”) from the EPA and a request for the production of documents from the United States Attorney’s Office for North Dakota relating to alleged violations of the Clean Air Act (“CAA”), at certain Targa Badlands LLC compressor stations. The EPA NOV and subpoena stem from inspections the EPA conducted at the compressor stations on June 15, 2023, as well as related records reviews. In October 2024, we began negotiations with the U.S. Attorney’s Office with respect to resolution of a single-count information alleging a violation of the CAA related to untimely installation of monitoring equipment at one compressor station, which carries a maximum fine of $500,000, and we entered into a Plea Agreement on December 16, 2024 reflecting these terms. In early July 2025, we entered into a Consent Agreement and Final Order with the EPA that

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resolves the allegations contained in the EPA NOV by requiring, among other things, payment of an administrative penalty in the amount of approximately $3.2 million.

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 14 years.

			2025				2026				2027 and after
Fixed consideration to be recognized as of June 30, 2025			$	198.6			$	405.5			$	2,137.4

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.

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 June 30, 2025 and December 31, 2024 was $125.7 million and $119.9 million, respectively.

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 six months ended June 30, 2025 is higher than the U.S. corporate statutory rate of 21% primarily due to state income taxes, partially offset by excess tax-deductible stock compensation. Our effective tax rate for the three and six months ended June 30, 2024 was lower than the U.S. corporate statutory rate of 21% primarily due to income allocated to noncontrolling interests that is not taxable to the Company, partially offset by state income taxes.

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 June 30, 2025 and December 31, 2024, our valuation allowance was $5.9 million.

We are subject to tax in the U.S. and various state jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. As of June 30, 2025, Internal Revenue Service (“IRS”) examinations are currently in process for the 2019, 2020 and 2022 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 do not expect there to be any audit adjustments that would materially change our taxable income.

On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (the “OBBBA”) into law. Among other things, the OBBBA indefinitely extends the 100% first-year depreciation allowance on qualified property placed in service after January 19, 2025, includes favorable modifications to the business interest expense limitation, and otherwise extends and enhances certain key provisions of the Tax Cuts & Jobs Act. The OBBBA has multiple effective dates with respect to its various provisions, with certain provisions effective in 2025. We are currently assessing the impacts of the OBBBA on our consolidated financial statements, and while we do not expect it to have a material impact on our results of operations, we do expect it to provide a benefit to our cash flows from operating activities.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the OBBBA, and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT at least through 2026. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future. As a result, our

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current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA, the OBBBA and the CAMT, we will continue to monitor and evaluate the potential future impact to our financial statements.

Note 15 — Supplemental Cash Flow Information

	Six Months Ended June 30,
	2025					2024
Cash:
Interest paid, net of capitalized interest (1)	$		363.4			$		379.0
Income taxes paid, net of refunds			21.1					9.5
Non-cash investing activities:
Impact of net accruals on capital expenditures	$		(187.4	)		$		160.7
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests	$		(13.5	)		$		(0.6	)

(1)Interest capitalized on major projects was $32.4 million and $33.8 million for the six months ended June 30, 2025 and 2024.

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.

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 our NGL pipeline system, 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. 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 June 30, 2025
		Gathering and Processing				Logistics and Transportation				Total Reportable Segments				Other				Corporate and Eliminations				Total
Revenues
Sales of commodities		$	203.3			$	3,152.5			$	3,355.8			$	280.5			$	—			$	3,636.3
Fees from midstream services			410.6				213.2				623.8				—				—				623.8
			613.9				3,365.7				3,979.6				280.5				—				4,260.1
Intersegment revenues
Sales of commodities			1,131.5				49.2				1,180.7				—				(1,180.7	)			—
Fees from midstream services			0.3				7.5				7.8				—				(7.8	)			—
			1,131.8				56.7				1,188.5				—				(1,188.5	)			—
Revenues		$	1,745.7			$	3,422.4			$	5,168.1			$	280.5			$	(1,188.5	)		$	4,260.1
Operating expenses		$	219.4			$	105.4			$	324.8			$	—
Other segment items (1)			938.7				2,684.6				3,623.3				—
Operating margin			587.6				632.4				1,220.0				280.5
Other financial information:
Total assets (2)		$	13,937.9			$	9,333.0			$	23,270.9			$	0.1			$	241.8			$	23,512.8
Goodwill			45.2				—				45.2				—				—				45.2
Capital expenditures			461.0				421.8				882.8				—				9.7				892.5

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		Three Months Ended June 30, 2024
		Gathering and Processing				Logistics and Transportation				Total Reportable Segments				Other				Corporate and Eliminations				Total
Revenues
Sales of commodities		$	254.3			$	2,759.0			$	3,013.3			$	(46.6	)		$	—			$	2,966.7
Fees from midstream services			391.3				204.0				595.3				—				—				595.3
			645.6				2,963.0				3,608.6				(46.6	)			—				3,562.0
Intersegment revenues
Sales of commodities			872.5				25.8				898.3				—				(898.3	)			—
Fees from midstream services			0.3				7.1				7.4				—				(7.4	)			—
			872.8				32.9				905.7				—				(905.7	)			—
Revenues		$	1,518.4			$	2,995.9			$	4,514.3			$	(46.6	)		$	(905.7	)		$	3,562.0
Operating expenses		$	205.7			$	85.4			$	291.1			$	—
Other segment items (1)			740.1				2,362.8				3,102.9				—
Operating margin			572.6				547.7				1,120.3				(46.6	)
Other financial information:
Total assets (2)		$	12,956.0			$	8,117.7			$	21,073.7			$	0.5			$	190.0			$	21,264.2
Goodwill			45.2				—				45.2				—				—				45.2
Capital expenditures			438.9				408.8				847.7				—				(1.0	)			846.7

		Six Months Ended June 30, 2025
		Gathering and Processing				Logistics and Transportation				Total Reportable Segments				Other				Corporate and Eliminations				Total
Revenues
Sales of commodities		$	404.0			$	7,085.0			$	7,489.0			$	31.7			$	—			$	7,520.7
Fees from midstream services			885.7				415.2				1,300.9				—				—				1,300.9
			1,289.7				7,500.2				8,789.9				31.7				—				8,821.6
Intersegment revenues
Sales of commodities			2,648.5				108.6				2,757.1				—				(2,757.1	)			—
Fees from midstream services			0.5				14.6				15.1				—				(15.1	)			—
			2,649.0				123.2				2,772.2				—				(2,772.2	)			—
Revenues		$	3,938.7			$	7,623.4			$	11,562.1			$	31.7			$	(2,772.2	)		$	8,821.6
Operating expenses		$	427.6			$	200.9			$	628.5			$	—
Other segment items (1)			2,321.3				6,143.4				8,464.7				—
Operating margin			1,189.8				1,279.1				2,468.9				31.7
Other financial information:
Total assets (2)		$	13,937.9			$	9,333.0			$	23,270.9			$	0.1			$	241.8			$	23,512.8
Goodwill			45.2				—				45.2				—				—				45.2
Capital expenditures			894.2				596.5				1,490.7				—				20.1				1,510.8

		Six Months Ended June 30, 2024
		Gathering and Processing				Logistics and Transportation				Total Reportable Segments				Other				Corporate and Eliminations				Total
Revenues
Sales of commodities		$	527.2			$	6,450.8			$	6,978.0			$	(68.7	)		$	—			$	6,909.3
Fees from midstream services			804.4				410.7				1,215.1				—				—				1,215.1
			1,331.6				6,861.5				8,193.1				(68.7	)			—				8,124.4
Intersegment revenues
Sales of commodities			2,003.5				72.7				2,076.2				—				(2,076.2	)			—
Fees from midstream services			(2.0	)			14.1				12.1				—				(12.1	)			—
			2,001.5				86.8				2,088.3				—				(2,088.3	)			—
Revenues		$	3,333.1			$	6,948.3			$	10,281.4			$	(68.7	)		$	(2,088.3	)		$	8,124.4
Operating expenses		$	393.7			$	175.4			$	569.1			$	—
Other segment items (1)			1,810.5				5,693.1				7,503.6				—
Operating margin			1,128.9				1,079.8				2,208.7				(68.7	)
Other financial information:
Total assets (2)		$	12,956.0			$	8,117.7			$	21,073.7			$	0.5			$	190.0			$	21,264.2
Goodwill			45.2				—				45.2				—				—				45.2
Capital expenditures			873.9				702.4				1,576.3				—				0.1				1,576.4

(1)“Other segment items” represents Product purchases and fuel.

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(2)Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, margin deposit, prepaids, property, plant and equipment and debt issuance costs for our revolving credit facility.

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

		Three Months Ended June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas		$	458.2			$	158.6			$	1,140.1			$	653.3
NGL			2,832.9				2,719.6				6,209.7				6,065.3
Condensate and crude oil			111.3				145.1				228.3				282.4
			3,402.4				3,023.3				7,578.1				7,001.0
Non-customer revenue:
Derivative activities - Hedge			27.7				32.2				21.6				29.0
Derivative activities - Non-hedge (1)			206.2				(88.8	)			(79.0	)			(120.7	)
			233.9				(56.6	)			(57.4	)			(91.7	)
Total sales of commodities			3,636.3				2,966.7				7,520.7				6,909.3
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing			403.7				385.7				872.7				791.5
NGL transportation, fractionation and services		83.2					75.2				160.0				148.7
Storage, terminaling and export			120.9				114.5				252.7				240.3
Other			16.0			19.9				15.5					34.6
Total fees from midstream services			623.8				595.3				1,300.9				1,215.1
Total revenues		$	4,260.1			$	3,562.0			$	8,821.6			$	8,124.4

(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 June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Total reportable segments operating margin		$	1,220.0			$	1,120.3			$	2,468.9			$	2,208.7
Other operating margin			280.5				(46.6	)			31.7				(68.7	)
Depreciation and amortization expense			(373.7	)			(348.6	)			(741.3	)			(689.1	)
General and administrative expense			(95.0	)			(98.3	)			(189.5	)			(184.8	)
Other operating income (expense)			1.8				0.2				7.1				0.3
Interest expense, net			(218.4	)			(176.0	)			(415.5	)			(404.6	)
Equity earnings (loss)			5.1				2.9				10.6				5.6
Other, net			1.0				(0.7	)			1.3				1.3
Income (loss) before income taxes		$	821.3			$	453.2			$	1,173.3			$	868.7

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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 in our annual report on Form 10-K for the year ended December 31, 2024 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q for the quarter ended June 30, 2025 (“Quarterly Report”).

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 infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic 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 our 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.

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 our NGL pipeline system, 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 Basin Processing Expansions

•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 commenced operations in the first quarter of 2025.

•In May 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Pembrook II plant”). The Pembrook II plant is expected to begin operations in the third quarter of 2025.

•In August 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose II plant”). The Bull Moose II plant is expected to begin operations in the fourth quarter of 2025.

•In August 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “East Pembrook plant”). The East Pembrook plant is expected to begin operations in the second quarter of 2026.

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•In November 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Falcon II plant”). The Falcon II plant is expected to begin operations in the second quarter of 2026.

•In November 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “East Driver plant”). The East Driver plant is expected to begin operations in the third quarter of 2026.

•In August 2025, we announced we are ordering long-lead items for our next potential gas plants across the Permian Basin.

Fractionation Expansions

•In January 2023, we reached an agreement with our partners in Gulf Coast Fractionators (“GCF”) to reactivate GCF’s 135 MBbl/d fractionation facility. GCF commenced operations in the first quarter of 2025.

•In May 2024, we announced plans to construct a new 150 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 11”). Train 11 is expected to begin operations in the second quarter of 2026.

•In February 2025, we announced plans to construct a new 150 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 12”). Train 12 is expected to begin operations in the first quarter of 2027.

NGL Pipeline Expansion

•In February 2025, we announced an intra-Delaware Basin expansion of our Grand Prix pipeline system in the Permian Delaware. The expansion is expected to begin operations in the second quarter of 2026.

LPG Export Expansion

•In February 2025, we announced an expansion of our LPG export capabilities at our Galena Park Marine Terminal, to include the addition of a new pipeline from Mont Belvieu to Galena Park and additional refrigeration. Our effective export capacity will increase up to 19 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The expansion is expected to be completed in the third quarter of 2027.

Natural Gas Pipeline Extension

•In August 2025, we announced a 43-mile extension of our Bull Run intrastate natural gas pipeline (the “Bull Run Extension”) to expand and enhance connectivity of our Permian Delaware system to the WAHA hub in West Texas. The Bull Run Extension is expected to begin operations in the first quarter of 2027.

Joint Ventures

On July 31, 2024, we entered into a joint venture (“Blackcomb Joint Venture”) to construct and operate the Blackcomb pipeline. The Blackcomb Joint Venture is owned 70.0% by WPC, 17.5% by Targa, and 12.5% by MPLX LP. WPC is a joint venture owned 50.6% by WhiteWater, 30.4% by MPLX LP, and 19.0% by Enbridge Inc. The Blackcomb pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 365 miles of 42-inch pipeline from the Permian Basin in West Texas to the Agua Dulce area in South Texas, and is expected to be in service in the second half of 2026, pending the receipt of customary regulatory and other approvals.

On April 3, 2025, WhiteWater announced the Blackcomb Joint Venture has reached a final investment decision to construct the Traverse pipeline. The bi-directional Traverse pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 160 miles of pipeline between Agua Dulce and the Katy area and is expected to be in service in 2027, pending the receipt of customary regulatory and other approvals. Both the Blackcomb and Traverse pipelines will be operated by an affiliate of WhiteWater.

On March 5, 2025, we completed the acquisition of Blackstone’s 45% interest in Targa Badlands LLC (“Targa Badlands”) for aggregate consideration of $1.8 billion in cash (the “Badlands Transaction”). As a result of the acquisition, we own 100% of the interests in and earnings of Targa Badlands effective January 1, 2025.

For additional information, see Note 4 – Joint Ventures and Acquisitions to our Consolidated Financial Statements.

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Capital Allocation

In April 2025, we declared an increase to our quarterly common dividend to $1.00 per common share, or $4.00 per common share annualized, effective for the first quarter of 2025.

In May 2023, our Board of Directors approved a $1.0 billion common share repurchase program (the “2023 Share Repurchase Program”). During the first quarter of 2025, we exhausted the 2023 Share Repurchase Program.

In July 2024, our Board of Directors approved a $1.0 billion common share repurchase program (the “2024 Share Repurchase Program”). In addition, in August 2025, our Board of Directors approved a new $1.0 billion common share repurchase program (the “2025 Share Repurchase Program” and, together with the 2024 Share Repurchase Program, the “Share Repurchase Programs”). We are not obligated to repurchase any specific dollar amount or number of shares under the Share Repurchase Programs and may discontinue these programs at any time.

For the three and six months ended June 30, 2025, we repurchased 1,955,099 shares and 2,606,262 shares of our common stock at a weighted average per share price of $165.86 and $172.35 for a total net cost of $324.3 million and $449.2 million, respectively. As of June 30, 2025, there was $566.2 million remaining under the 2024 Share Repurchase Program. The amount authorized under the 2025 Share Repurchase Program is in addition to the amount that remained under the 2024 Share Repurchase Program.

Financing Activities

In February 2025, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent and Swing Line Lender, the letter of credit issuers party thereto and the other lenders party thereto (the “TRGP Revolver”). The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion and matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times. In connection with our entry into the TRGP Revolver, we terminated our previous revolving credit facility (the “Previous TRGP Revolver”).

In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 (the “5.550% Notes due 2035”) and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055 (the “6.125% Notes due 2055”), resulting in net proceeds of approximately $2.0 billion. The 5.550% Notes due 2035 and 6.125% Notes due 2055 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. We used the net proceeds from the debt issuance to fund the Badlands Transaction and the remaining net proceeds for general corporate purposes, including to repay borrowings under our unsecured commercial paper note program (the “Commercial Paper Program”).

In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 (the “4.900% Notes due 2030”) and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036 (the “5.650% Notes due 2036”), resulting in net proceeds of approximately $1.5 billion. The 4.900% Notes due 2030 and 5.650% Notes due 2036 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. We used the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 (the “6.500% Notes due 2027”) in July 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In July 2025, the Partnership amended the $600.0 million accounts receivable securitization facility (the “Securitization Facility”) to, among other things, extend the facility termination date to August 31, 2026.

For additional information about our recent debt-related transactions, see Note 7 – Debt Obligations to our Consolidated Financial Statements.

Corporation Tax Matters

As of June 30, 2025, Internal Revenue Service (the “IRS”) examinations are currently in process for the 2019, 2020 and 2022 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 do not expect there to be any audit adjustments that would materially change our taxable income.

Federal statutes of limitations for returns filed in 2021 (for calendar year 2020) have expired. The 2019 returns under examination have a statute extension to December 2025. The statute of limitations expired on substantially all 2020 state income tax returns that were filed

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prior to October 15, 2021. For Texas, the statute of limitations has expired for 2020 returns (for calendar year 2019). However, tax authorities could review and adjust carryover attributes (e.g., net operating losses) generated in a closed tax year if utilized in an open tax year.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the One Big Beautiful Bill Act (the “OBBBA”), and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT at least through 2026. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA, the OBBBA, and the CAMT, we will continue to monitor and evaluate the potential future impact to our financial statements.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see 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 natural gas, NGLs and crude oil, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of natural gas, NGLs and crude oil throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our Downstream 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, adjusted cash flow from operations, 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 and crude oil supplies 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 natural gas and crude oil 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 our NGL pipeline system, 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

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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, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP 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

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•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.

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow

We define adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit. We define adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures (net of any reimbursements of project costs) and growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations 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.

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Our Non-GAAP Financial Measures

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2025				2024				2025				2024
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	629.1			$	298.5			$	899.6			$	573.7
Interest (income) expense, net		218.4				176.0				415.5				404.6
Income tax expense (benefit)		184.1				94.3				256.3				177.1
Depreciation and amortization expense		373.7				348.6				741.3				689.1
(Gain) loss on sale or disposition of assets		(0.7	)			(0.6	)			(1.2	)			(1.6	)
Write-down of assets		9.6				0.3				11.6				1.2
(Gain) loss from financing activities		—				0.8				0.6				0.8
Equity (earnings) loss		(5.1	)			(2.9	)			(10.6	)			(5.6	)
Distributions from unconsolidated affiliates		6.2				5.9				11.1				12.2
Compensation on equity grants		17.1				15.1				34.7				29.7
Risk management activities		(280.5	)			46.6				(31.7	)			68.8
Noncontrolling interests adjustments (1)		2.5				1.7				5.7				0.8
Litigation expense (2)		8.6				—				8.6				—
Adjusted EBITDA	$	1,163.0			$	984.3			$	2,341.5			$	1,950.8
Interest expense on debt obligations (3)		(214.3	)			(172.4	)			(407.5	)			(397.3	)
Cash taxes		(14.3	)			(3.4	)			(29.6	)			(6.3	)
Adjusted Cash Flow from Operations	$	934.4			$	808.5			$	1,904.4			$	1,547.2
Maintenance capital expenditures, net (4)		(58.9	)			(52.8	)			(106.2	)			(102.7	)
Growth capital expenditures, net (4)		(885.1	)			(798.7	)			(1,479.6	)			(1,484.5	)
Adjusted Free Cash Flow	$	(9.6	)		$	(43.0	)		$	318.6			$	(40.0	)

(1)Represents adjustments related to our subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within our WestTX joint venture not subject to noncontrolling interest accounting.

(2)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.

(3)Excludes amortization of interest expense. The three and six months ended June 30, 2024 includes $0.9 million and $55.8 million, respectively, of interest expense on a 2024 legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp (the “Splitter Agreement”).

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

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Consolidated Results of Operations

The following table and discussion summarize our consolidated results of operations for the periods indicated:

	Three Months Ended June 30,																Six Months Ended June 30,
	2025				2024				2025 vs. 2024								2025				2024				2025 vs. 2024
	(In millions)
Revenues:
Sales of commodities	$	3,636.3			$	2,966.7			$	669.6				23	%		$	7,520.7			$	6,909.3			$	611.4			9	%
Fees from midstream services		623.8				595.3				28.5				5	%			1,300.9				1,215.1				85.8			7	%
Total revenues		4,260.1				3,562.0				698.1				20	%			8,821.6				8,124.4				697.2			9	%
Product purchases and fuel		2,436.0				2,197.4				238.6				11	%			5,693.8				5,415.4				278.4			5	%
Operating expenses		323.6				290.7				32.9				11	%			627.2				568.7				58.5			10	%
Depreciation and amortization expense		373.7				348.6				25.1				7	%			741.3				689.1				52.2			8	%
General and administrative expense		95.0				98.3				(3.3	)			(3	%)			189.5				184.8				4.7			3	%
Other operating (income) expense		(1.8	)			(0.2	)			(1.6	)		NM					(7.1	)			(0.3	)			(6.8	)	NM
Income (loss) from operations		1,033.6				627.2				406.4				65	%			1,576.9				1,266.7				310.2			24	%
Interest expense, net		(218.4	)			(176.0	)			(42.4	)			24	%			(415.5	)			(404.6	)			(10.9	)		3	%
Equity earnings (loss)		5.1				2.9				2.2				76	%			10.6				5.6				5.0			89	%
Other, net		1.0				(0.9	)			1.9			NM					1.3				1.0				0.3			30	%
Income tax (expense) benefit		(184.1	)			(94.3	)			(89.8	)			95	%			(256.3	)			(177.1	)			(79.2	)		45	%
Net income (loss)		637.2				358.9				278.3				78	%			917.0				691.6				225.4			33	%
Less: Net income (loss) attributable to noncontrolling interests		8.1				60.4				(52.3	)			(87	%)			17.4				117.9				(100.5	)		(85	%)
Net income (loss) attributable to Targa Resources Corp.		629.1				298.5				330.6				111	%			899.6				573.7				325.9			57	%
Premium on repurchase of noncontrolling interests, net of tax		—				—				—				—				70.5				—				70.5			100	%
Net income (loss) attributable to common shareholders	$	629.1			$	298.5			$	330.6				111	%		$	829.1			$	573.7			$	255.4			45	%
Financial data:
Adjusted EBITDA (1)	$	1,163.0			$	984.3			$	178.7				18	%		$	2,341.5			$	1,950.8			$	390.7			20	%
Adjusted cash flow from operations (1)		934.4				808.5				125.9				16	%			1,904.4				1,547.2				357.2			23	%
Adjusted free cash flow (1)		(9.6	)			(43.0	)			33.4				78	%			318.6				(40.0	)			358.6		NM

(1)Adjusted EBITDA, adjusted cash flow from operations 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 June 30, 2025 Compared to Three Months Ended June 30, 2024

The increase in commodity sales reflected higher NGL volumes ($304.2 million), higher natural gas prices ($296.4 million) and the favorable impact of hedges ($290.5 million), partially offset by lower NGL and condensate prices ($217.3 million).

The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

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

The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes, which were associated with system expansions and the planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

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

The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.

The increase in interest expense, net, was primarily due to higher borrowings in 2025.

The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.

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The decrease in net income attributable to noncontrolling interests was primarily due to the Badlands Transaction in the first quarter of 2025 and the acquisition of the remaining membership interest in Cedar Bayou Fractionators, L.P. in the fourth quarter of 2024 (the “CBF Acquisition”).

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

The increase in commodity sales reflected higher natural gas prices ($503.7 million), higher NGL volumes ($133.8 million) and the favorable impact of hedges ($34.4 million), partially offset by lower condensate prices ($41.6 million) and lower natural gas and condensate volumes ($29.3 million).

The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

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

The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes, which were associated with system expansions and the planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

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

The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.

The increase in interest expense, net, was primarily due to higher borrowings in 2025, partially offset by the recognition of cumulative interest on a legal ruling associated with the Splitter Agreement in 2024.

The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.

The decrease in net income attributable to noncontrolling interests was primarily due to the Badlands Transaction in the first quarter of 2025 and the CBF Acquisition in the fourth quarter of 2024.

The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in 2025.

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:
June 30, 2025		$	587.6			$	632.4			$	280.5
June 30, 2024			572.6				547.7				(46.6	)
Six Months Ended:
June 30, 2025		$	1,189.8			$	1,279.1			$	31.7
June 30, 2024			1,128.9				1,079.8				(68.7	)

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Gathering and Processing Segment

	Three Months Ended June 30,																			Six Months Ended June 30,
	2025					2024					2025 vs. 2024									2025					2024					2025 vs. 2024
		(In millions, except operating statistics and price amounts)
Operating margin	$		587.6			$		572.6			$		15.0				3	%		$		1,189.8			$		1,128.9			$		60.9				5	%
Operating expenses			219.4					205.7					13.7				7	%				427.6					393.7					33.9				9	%
Adjusted operating margin	$		807.0			$		778.3			$		28.7				4	%		$		1,617.4			$		1,522.6			$		94.8				6	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			3,106.2					2,866.4					239.8				8	%				3,046.3					2,806.3					240.0				9	%
Permian Delaware			3,171.8					2,805.1					366.7				13	%				3,096.5					2,727.0					369.5				14	%
Total Permian			6,278.0					5,671.5					606.5				11	%				6,142.8					5,533.3					609.5				11	%
SouthTX			381.5					339.4					42.1				12	%				338.5					322.2					16.3				5	%
North Texas			172.6					191.8					(19.2	)			(10	%)				172.1					188.1					(16.0	)			(9	%)
SouthOK (5)			322.2					361.5					(39.3	)			(11	%)				320.1					359.3					(39.2	)			(11	%)
WestOK			210.0					215.1					(5.1	)			(2	%)				205.1					212.6					(7.5	)			(4	%)
Total Central			1,086.3					1,107.8					(21.5	)			(2	%)				1,035.8					1,082.2					(46.4	)			(4	%)
Badlands (5) (6)			130.9					143.9					(13.0	)			(9	%)				133.9					135.5					(1.6	)			(1	%)
Total Field			7,495.2					6,923.2					572.0				8	%				7,312.5					6,751.0					561.5				8	%
Coastal			398.8					467.0					(68.2	)			(15	%)				398.8					495.8					(97.0	)			(20	%)
Total			7,894.0					7,390.2					503.8				7	%				7,711.3					7,246.8					464.5				6	%
NGL production, MBbl/d (3)
Permian Midland (4)			450.1					424.1					26.0				6	%				439.9					408.4					31.5				8	%
Permian Delaware			406.7					364.5					42.2				12	%				386.8					335.7					51.1				15	%
Total Permian			856.8					788.6					68.2				9	%				826.7					744.1					82.6				11	%
SouthTX			39.8					42.2					(2.4	)			(6	%)				34.3					35.6					(1.3	)			(4	%)
North Texas			21.3					23.5					(2.2	)			(9	%)				21.1					22.7					(1.6	)			(7	%)
SouthOK (5)			43.0					43.5					(0.5	)			(1	%)				38.1					35.8					2.3				6	%
WestOK			16.1					15.5					0.6				4	%				15.6					13.6					2.0				15	%
Total Central			120.2					124.7					(4.5	)			(4	%)				109.1					107.7					1.4				1	%
Badlands (5)			16.6					18.0					(1.4	)			(8	%)				16.5					16.3					0.2				1	%
Total Field			993.6					931.3					62.3				7	%				952.3					868.1					84.2				10	%
Coastal			31.6					34.4					(2.8	)			(8	%)				32.2					36.7					(4.5	)			(12	%)
Total			1,025.2					965.7					59.5				6	%				984.5					904.8					79.7				9	%
Crude oil, Badlands, MBbl/d			90.3					99.1					(8.8	)			(9	%)				98.7					96.8					1.9				2	%
Crude oil, Permian, MBbl/d			26.2					27.9					(1.7	)			(6	%)				27.6					27.7					(0.1	)			—
Natural gas sales, BBtu/d (3)			2,819.5					2,843.5					(24.0	)			(1	%)				2,706.7					2,747.0					(40.3	)			(1	%)
NGL sales, MBbl/d (3)			606.4					569.7					36.7				6	%				588.4					534.3					54.1				10	%
Condensate sales, MBbl/d			20.1					21.2					(1.1	)			(5	%)				19.1					20.1					(1.0	)			(5	%)
Average realized prices (7):
Natural gas, $/MMBtu			1.01					0.10					0.91			NM						1.59					0.78					0.81				104	%
NGL, $/gal			0.41					0.44					(0.03	)			(7	%)				0.46					0.46					—				—
Condensate, $/Bbl			63.79					72.83					(9.04	)			(12	%)				67.80					74.91					(7.11	)			(9	%)

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

(2)Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands during 2024.

(3)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

(4)Permian Midland includes operations in WestTX, of which we own a 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5)Operations include facilities that are not wholly owned by us.

(6)Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.

(7)Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.

36

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

		Three Months Ended June 30, 2025												Three Months Ended June 30, 2024
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			7.4			$	2.095			$	15.5				10.5			$	2.581			$	27.1
NGL (MMgal)			83.6				(0.005	)			(0.4	)			112.0				0.046				5.1
Crude oil (MBbl)			0.7				7.714				5.4				0.4				(11.250	)			(4.5	)
										$	20.5											$	27.7

		Six Months Ended June 30, 2025												Six Months Ended June 30, 2024
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			15.1			$	1.517			$	22.9				26.2			$	1.733			$	45.4
NGL (MMgal)			181.2				(0.038	)			(7.0	)			246.1				0.028				6.8
Crude oil (MBbl)			1.4				4.357				6.1				0.9				(8.222	)			(7.4	)
										$	22.0											$	44.8

(1)The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2024

The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian, partially offset by lower volumes in other areas. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, and continued strong producer activity.

The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, and continued strong producer activity.

The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.

Logistics and Transportation Segment

	Three Months Ended June 30,																	Six Months Ended June 30,
	2025					2024					2025 vs. 2024							2025					2024					2025 vs. 2024
	(In millions, except operating statistics)
Operating margin	$		632.4			$		547.7			$		84.7			15%		$		1,279.1			$		1,079.8			$		199.3			18%
Operating expenses			105.4					85.4					20.0			23%				200.9					175.4					25.5			15%
Adjusted operating margin	$		737.8			$		633.1			$		104.7			17%		$		1,480.0			$		1,255.2			$		224.8			18%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes			961.2					783.5					177.7			23%				902.7					750.6					152.1			20%
Fractionation volumes			969.1					902.2					66.9			7%				974.5					849.7					124.8			15%
Export volumes			423.1					394.1					29.0			7%				435.3					416.6					18.7			4%
NGL sales			1,151.1					1,018.4					132.7			13%				1,168.6					1,123.0					45.6			4%

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

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2024

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, a full quarter of operation of Train 9 which was added during the second quarter of 2024, the in-service of

37

Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Fractionation volumes were higher despite a planned turnaround at a portion of our facilities in Mont Belvieu, Texas. LPG export margin increased due to higher volumes and fees.

The increase in operating expenses was predominately due to a planned turnaround and system expansions.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, a full quarter of operation of Train 9 which was added during the second quarter of 2024, the in-service of Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Fractionation volumes were higher despite a planned turnaround at a portion of our facilities in Mont Belvieu, Texas. LPG export margin increased due to higher volumes and fees.

The increase in operating expenses was predominately due to system expansions and a planned turnaround.

Other

		Three Months Ended June 30,												Six Months Ended June 30,
		2025				2024				2025 vs. 2024				2025				2024				2025 vs. 2024
		(In millions)
Operating margin		$	280.5			$	(46.6	)		$	327.1			$	31.7			$	(68.7	)		$	100.4
Adjusted operating margin		$	280.5			$	(46.6	)		$	327.1			$	31.7			$	(68.7	)		$	100.4

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

Our Liquidity and Capital Resources

As of June 30, 2025, inclusive of our consolidated joint venture accounts, we had $113.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next twelve months to satisfy our obligations, including our day-to-day operations, growth capital expenditures, dividend payments, maintenance capital expenditures, debt service and other anticipated obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, see “Recent Developments.”

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of July 31, 2025, was:

		Consolidated Total
		(In millions)
Cash on hand (1)		$	190.2
Total availability under the Securitization Facility			600.0
Total availability under the TRGP Revolver and Commercial Paper Program			3,500.0
			4,290.2
Outstanding borrowings under the Securitization Facility			(600.0	)
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program			(1,035.0	)
Outstanding letters of credit under the TRGP Revolver			(26.7	)
Total liquidity		$	2,628.5

38

(1)Includes cash held in our consolidated joint venture accounts.

Other potential capital resources associated with our existing arrangements include our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of June 30, 2025, we had $9.4 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, as well as liquids valuations; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.

Our working capital as of June 30, 2025 decreased $93.2 million compared to December 31, 2024. The decrease was primarily due to the reclassification of the 6.500% Notes due 2027 to Current debt obligations on our Consolidated Balance Sheets as a result of the issuance of a conditional notice of redemption in June 2025. This decrease was partially offset by a lower outstanding balance on the Securitization Facility, higher NGL inventory balance as well as lower payables and accrued liabilities, including payable balances related to capital spending on growth projects.

Long-term Financing

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

In February 2025, we entered into the TRGP Revolver, which provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $150.0 million. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver.

In February 2025, we completed an underwritten public offering of the 5.550% Notes due 2035 and the 6.125% Notes 2055, resulting in net proceeds of approximately $2.0 billion. We used the net proceeds from the debt issuance to fund the Badlands Transaction and for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In June 2025, we completed an underwritten public offering of the 4.900% Notes due 2030 and the 5.650% Notes due 2036, resulting in net proceeds of approximately $1.5 billion. We used the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Notes due 2027 in July 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or 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, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.

For information about our debt obligations, see Note 7 – Debt Obligations to our Consolidated Financial Statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

39

Compliance with Debt Covenants

As of June 30, 2025, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

Six Months Ended June 30,
2025				2024				2025 vs. 2024
(In millions)
$	1,812.7			$	1,780.9			$	31.8

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

The increase in net cash provided by operating activities was primarily due to higher collections from customers resulting from increased revenues offset by higher payments related to product purchases and fuel as well as higher operating expenses and lower settlements for hedge transactions. In addition, during 2024, we made a nonrecurring one-time payment associated with the Splitter Agreement.

Cash Flows from Investing Activities

Six Months Ended June 30,
2025				2024				2025 vs. 2024
(In millions)
$	(1,770.1	)		$	(1,427.7	)		$	(342.4	)

The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities in the Permian region and Mont Belvieu, Texas, and contributions to unconsolidated affiliates.

Cash Flows from Financing Activities

	Six Months Ended June 30,
	2025				2024
	(In millions)
Source of Financing Activities, net
Debt, including financing costs	$	2,625.7			$	579.8
Repurchase of noncontrolling interests		(1,800.4	)			(1.3	)
Dividends paid to common shareholders		(385.6	)			(284.2	)
Contributions from (distributions to) noncontrolling interests, net		(24.2	)			(107.3	)
Repurchases of shares		(502.3	)			(515.5	)
Net cash provided by (used in) financing activities	$	(86.8	)		$	(328.5	)

The decrease in net cash used in financing activities was due to higher proceeds from debt financings in 2025, and lower distributions to noncontrolling interests subsequent to the CBF Acquisition in the fourth quarter of 2024 and the Badlands Transaction in the first quarter of 2025, partially offset by higher repurchases of noncontrolling interests due to the Badlands Transaction and higher dividends paid. The increase in cash flows from our debt activity was due to proceeds from the issuance of our senior unsecured notes in 2025, partially offset by higher repayments under the Commercial Paper Program and Securitization Facility. In addition, in 2024, we fully repaid the remaining balance outstanding under the $1.5 billion unsecured term loan facility.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior unsecured notes, subject to certain limited exceptions.

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In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. The composition of the Obligated Group changed in connection with our entry into the TRGP Revolver. As a result, the following supplemental summarized combined financial information of the Obligated Group appearing below supersedes such information appearing in our Annual Report.

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

Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent period presented follows:

Summarized Combined Balance Sheet Information
		June 30, 2025				December 31, 2024
		(In millions)
ASSETS
Current assets		$	127.3			$	127.8
Current assets - affiliates			3.0				22.7
Long-term assets			82.8				76.4
Total assets		$	213.1			$	226.9
LIABILITIES AND OWNERS’ EQUITY (DEFICIT)
Current liabilities		$	900.8			$	262.0
Long-term liabilities			4,419.9				5,121.7
Targa Resources Corp. stockholders’ equity (deficit)			(5,107.6	)			(5,156.8	)
Total liabilities and owners’ equity (deficit)		$	213.1			$	226.9
Summarized Combined Statement of Operations Information
		Six Months Ended June 30, 2025				Year Ended December 31, 2024
		(In millions)
Operating income (loss)		$	(166.3	)		$	(328.0	)
Net income (loss)			(298.7	)			(583.0	)

Common Stock Dividends

The following table details the dividends on common stock declared and/or paid by us for the six months ended June 30, 2025:

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)
June 30, 2025		August 15, 2025		$	217.1			$	215.2			$	1.9			$	1.00000
March 31, 2025		May 15, 2025			219.0				216.9				2.1				1.00000
December 31, 2024		February 14, 2025			165.2				163.6				1.6				0.75000

The actual amount we declare as dividends in the future depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our Board of Directors deems relevant.

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Capital Expenditures

The following table details cash outlays for capital projects for the periods presented:

		Six Months Ended June 30,
		2025				2024
		(In millions)
Capital expenditures:
Growth (1)		$	1,403.8			$	1,470.2
Maintenance (2)			107.0				106.2
Gross capital expenditures			1,510.8				1,576.4
Change in capital project payables and accruals, net			187.5				(166.3	)
Cash outlays for capital projects		$	1,698.3			$	1,410.1

(1)Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $1,479.6 million and $1,484.5 million for the six months ended June 30, 2025 and 2024.

(2)Maintenance capital expenditures, net of contributions from noncontrolling interests, were $106.2 million and $102.7 million for the six months ended June 30, 2025 and 2024.

The decrease in growth capital expenditures was primarily due to timing of construction projects.

Off-Balance Sheet Arrangements

As of June 30, 2025, there were $58.6 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

The prices for natural gas, NGLs and crude oil are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2028. Market conditions may also impact our ability to enter into future commodity derivative contracts.

Commodity Price Risk

A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Realized settlements for derivative instruments designated as a hedge are classified in the same category as the items being hedged in Revenues within the Consolidated Statements of Operations.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of June 30, 2025, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities

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available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair values of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedges are documented pursuant to a standard International Swaps and Derivatives Association (“ISDA”) form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. While we have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).

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

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of June 30, 2025:

	Fair Value				Result of 10% Price Decrease				Result of 10% Price Increase
	(In millions)
Natural gas	$	(156.7	)		$	(97.3	)		$	(216.2	)
NGLs		0.4				83.5				(82.8	)
Crude oil		33.5				66.6				0.5
Total	$	(122.8	)		$	52.8			$	(298.5	)

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

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Our operating revenues increased (decreased) by $233.9 million and $(56.6) million during the three months ended June 30, 2025 and 2024, respectively, and $(57.4) million and $(91.7) million during the six months ended June 30, 2025 and 2024, respectively, as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of $172.2 million at December 31, 2024 to a net liability position of $122.8 million at June 30, 2025. The net liability position on our derivative contracts is primarily attributable to unfavorable movement in natural gas forward basis prices.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRGP Revolver, the Commercial Paper Program and the Securitization Facility. As of June 30, 2025, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRGP Revolver, the Commercial Paper Program and the Securitization Facility will also increase. As of June 30, 2025, we had $667.0 million in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $6.7 million based on our June 30, 2025 debt balances.

Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the ISDA agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and reduce our maximum loss due to counterparty credit risk by $18.7 million as of June 30, 2025. The range of losses attributable to our individual counterparties as of June 30, 2025 would be between $0.3 million and $8.2 million, depending on the counterparty in default.

For more information about our hedging activities, see Note 10 – Derivative Instruments and Hedging Activities and Note 11 – Fair Value Measurements to our Consolidated Financial Statements.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for credit losses was $0.7 million and $2.5 million as of June 30, 2025 and December 31, 2024, respectively.

During the three and six months ended June 30, 2025 and 2024, no customer comprised 10% or greater of our consolidated revenues.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2025, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

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Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended June 30, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 12 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A. Risk Factors.

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

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

Recent Sales of Unregistered Equity Securities.

None.

Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers.

Period		Total number of shares purchased (1)				Average price per share				Total number of shares purchased as part of publicly announced plans (2)				Maximum approximate dollar value of shares that may yet be purchased under the plan (in thousands) (2)
April 1, 2025 - April 30, 2025			533,201			$	167.34				532,210			$	801,432
May 1, 2025 - May 31, 2025			566,485			$	161.24				566,330			$	710,115
June 1, 2025 - June 30, 2025			856,600			$	168.03				856,559			$	566,187

(1)Includes 1,955,099 shares purchased under our 2024 Share Repurchase Program, as well as 1,187 shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.

(2)In July 2024, our Board of Directors approved the 2024 Share Repurchase Program for the repurchase of up to $1.0 billion of our outstanding common stock. In addition, in August 2025, our Board of Directors approved the 2025 Share Repurchase Program for the repurchase of up to $1.0 billion of our outstanding common stock. We are not obligated to repurchase any specific dollar amount or number of shares under the Share Repurchase Programs and may discontinue these programs at any time.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Rule 10b-5 Trading Plans.

During the three months ended June 30, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Item 6. Exhibits.

Number		Description
3.1		Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
3.2		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 26, 2021 (File No. 001-34991)).
3.3		Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State of the State of Delaware on March 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).

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Number		Description
3.4		Third Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 12, 2023 (File No. 001-34991)).
4.1		Eleventh Supplemental Indenture, dated as of June 18, 2025, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resource Corp.’s Current Report on Form 8-K filed June 18, 2025 (File No. 001-34991)).
4.2		Form of Notes (included in Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K filed June 18, 2025 (File No. 001-34991)).
10.1		Sixteenth Amendment to Receivables Purchase Agreement, dated as of July 28, 2025, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 28, 2025 (File No. 001-34991)).
22.1*		List of Subsidiary Guarantors.
31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH		Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents
104		The cover page from this Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, formatted in Inline XBRL (included with Exhibit 101 attachments).

* Filed herewith

** Furnished herewith

+ Management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Targa Resources Corp.
	(Registrant)
Date: August 7, 2025	By:		/s/ William A. Byers
			William A. Byers
			Chief Financial Officer
			(Principal Financial Officer)

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FAQ

How much revenue did Where Food Comes From (WFCF) report for Q2 2025?

WFCF generated $6.6 million in total revenue for the quarter ended June 30 2025.

Did WFCF’s earnings per share improve in Q2 2025?

Yes. Basic and diluted EPS increased to $0.11 from $0.09 in Q2 2024.

What is WFCF’s current cash position?

Cash and equivalents totaled $3.2 million at June 30 2025, up from $2.0 million at year-end.

Why did net income rise despite lower gross margin?

A $0.17 million unrealised Bitcoin gain and $0.05 million dividend income offset margin compression.

What are the terms of the Progressive Beef divestiture?

On July 22 2025 WFCF agreed to sell its 10% stake for ~$1.8 million cash plus 12,585 WFCF shares.

How many shares are outstanding after recent buybacks?

As of August 1 2025, 5,168,176 common shares were outstanding.

Does WFCF carry any interest-bearing debt?

No. The company remains debt-free and chose not to renew its prior line of credit.