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 March 31, 2023

or

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

For the transition period from _____ to _____

Commission File Number: 001-34991

 

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

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

(713) 584-1000

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

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

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

As of April 28, 2023, there were 226,019,124 shares of the registrant’s common stock, $0.001 par value, outstanding.

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Balance Sheets as of March 31, 2023 and December 31, 2022	4
Consolidated Statements of Operations for the three months ended March 31, 2023 and 2022	5
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2023 and 2022	6
Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the three months ended March 31, 2023 and 2022	7
Consolidated Statements of Cash Flows for the three months ended March 31, 2023 and 2022	9
Notes to Consolidated Financial Statements	10
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	39
PART II—OTHER INFORMATION
Item 1. Legal Proceedings	40
Item 1A. Risk Factors	40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3. Defaults Upon Senior Securities	40
Item 4. Mine Safety Disclosures	41
Item 5. Other Information	41
Item 6. Exhibits	41
SIGNATURES
Signatures	43

1

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

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

•actions taken by other countries with significant hydrocarbon production;

•the timing and success of business development efforts;

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

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

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

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

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

•weather and other natural phenomena, and related impacts;

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

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

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

•general economic, market and business conditions;

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

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

2

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2023 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

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

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

	March 31, 2023			December 31, 2022
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	211.8		$	219.0
Trade receivables, net of allowances of $2.5 million and $2.2 million at March 31, 2023 and December 31, 2022		1,023.4			1,408.4
Inventories		156.2			393.8
Assets from risk management activities		146.5			179.9
Other current assets		100.9			155.5
Total current assets		1,638.8			2,356.6
Property, plant and equipment, net		14,470.0			14,214.6
Intangible assets, net		2,638.6			2,734.6
Long-term assets from risk management activities		36.2			24.5
Investments in unconsolidated affiliates		134.7			131.3
Other long-term assets		107.2			98.4
Total assets	$	19,025.5		$	19,560.0
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable	$	1,255.3		$	1,448.8
Accrued liabilities		188.6			289.5
Interest payable		127.1			174.0
Liabilities from risk management activities		156.6			320.1
Current debt obligations		739.0			834.3
Total current liabilities		2,466.6			3,066.7
Long-term debt		11,439.6			10,702.1
Long-term liabilities from risk management activities		62.4			140.1
Deferred income taxes, net		298.3			327.7
Other long-term liabilities		346.4			341.2
Contingencies (see Note 12)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero shares issued and outstanding as of March 31, 2023 and December 31, 2022), net of discount		—			—
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 450,000,000 shares authorized as of March 31, 2023 and December 31, 2022)		0.2			0.2
Issued Outstanding
March 31, 2023 239,205,818 226,135,558
December 31, 2022 237,939,058 226,042,229
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, zero shares issued and outstanding)		—			—
Additional paid-in capital		3,146.0			3,702.3
Retained earnings (deficit)		(129.8	)		(626.8	)
Accumulated other comprehensive income (loss)		84.8			54.7
Treasury stock, at cost (13,070,260 shares as of March 31, 2023 and 11,896,829 shares as of December 31, 2022)		(550.5	)		(464.7	)
Total Targa Resources Corp. stockholders' equity		2,550.7			2,665.7
Noncontrolling interests		1,861.5			2,316.5
Total owners' equity		4,412.2			4,982.2
Total liabilities, Series A Preferred Stock and owners' equity	$	19,025.5		$	19,560.0

See notes to consolidated financial statements.

4

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,
	2023			2022
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Sales of commodities	$	4,025.0		$	4,566.2
Fees from midstream services		495.5			392.9
Total revenues		4,520.5			4,959.1
Costs and expenses:
Product purchases and fuel		3,019.0			4,204.1
Operating expenses		258.2			183.5
Depreciation and amortization expense		324.8			209.1
General and administrative expense		82.4			67.1
Other operating (income) expense		(0.6	)		(0.5	)
Income (loss) from operations		836.7			295.8
Other income (expense):
Interest expense, net		(168.0	)		(93.6	)
Equity earnings (loss)		(0.2	)		5.6
Gain (loss) from financing activities		—			(15.8	)
Other, net		(3.0	)		(0.5	)
Income (loss) before income taxes		665.5			191.5
Income tax (expense) benefit		(110.3	)		(22.9	)
Net income (loss)		555.2			168.6
Less: Net income (loss) attributable to noncontrolling interests		58.2			80.6
Net income (loss) attributable to Targa Resources Corp.		497.0			88.0
Premium on repurchase of noncontrolling interests, net of tax		490.7			53.1
Dividends on Series A Preferred Stock		—			21.8
Net income (loss) attributable to common shareholders	$	6.3		$	13.1
Net income (loss) per common share - basic	$	0.03		$	0.06
Net income (loss) per common share - diluted	$	0.03		$	0.06
Weighted average shares outstanding - basic		226.4			228.5
Weighted average shares outstanding - diluted		229.3			232.4

See notes to consolidated financial statements.

5

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended March 31,
	2023									2022
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax			After Tax
	(Unaudited)
	(In millions)
Net income (loss)							$	555.2								$	168.6
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$	83.9		$	(18.6	)		65.3		$	(387.1	)	$	86.6			(300.5	)
Settlements reclassified to revenues		(45.2	)		10.0			(35.2	)		145.7			(32.7	)		113.0
Other comprehensive income (loss)		38.7			(8.6	)		30.1			(241.4	)		53.9			(187.5	)
Comprehensive income (loss)								585.3									(18.9	)
Less: Comprehensive income (loss) attributable to noncontrolling interests								58.2									80.6
Comprehensive income (loss) attributable to Targa Resources Corp.							$	527.1								$	(99.5	)

See notes to consolidated financial statements.

6

TARGA RESOURCES CORP.

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

									Retained			Accumulated
						Additional			Earnings			Other		Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive		Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)		Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)
Balance, December 31, 2022		226,042		$	0.2	$	3,702.3		$	(626.8	)	$	54.7		11,897	$	(464.7	)	$	2,316.5		$	4,982.2		$	—
Compensation on equity grants		—			—		15.0			—			—		—		—			—			15.0			—
Dividend equivalent rights		—			—		(1.3	)		—			—		—		—			—			(1.3	)		—
Shares issued under compensation program		1,267			—		—			—			—		—		—			—			—			—
Shares tendered for tax withholding obligations		(449	)		—		—			—			—		449		(33.8	)		—			(33.8	)		—
Repurchases of common stock		(724	)		—		—			—			—		724		(52.0	)		—			(52.0	)		—
Common stock dividends
Dividends - $0.35 per share		—			—		—			(79.3	)		—		—		—			—			(79.3	)		—
Dividends in excess of retained earnings		—			—		(79.3	)		79.3			—		—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—		—		—			(56.1	)		(56.1	)		—
Contributions from noncontrolling interests		—			—		—			—			—		—		—			0.2			0.2			—
Repurchase of noncontrolling interests, net of tax		—			—		(490.7	)		—			—		—		—			(457.3	)		(948.0	)		—
Other comprehensive income (loss)		—			—		—			—			30.1		—		—			—			30.1			—
Net income (loss)		—			—		—			497.0			—		—		—			58.2			555.2			—
Balance, March 31, 2023		226,136		$	0.2	$	3,146.0		$	(129.8	)	$	84.8		13,070	$	(550.5	)	$	1,861.5		$	4,412.2		$	—

See notes to consolidated financial statements.

7

TARGA RESOURCES CORP.

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

									Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)
Balance, December 31, 2021		228,221		$	0.2	$	4,268.9		$	(1,822.3	)	$	(230.9	)		7,884	$	(204.1	)	$	3,166.9		$	5,178.7		$	749.7
Compensation on equity grants		—			—		13.5			—			—			—		—			—			13.5			—
Dividend equivalent rights		—			—		(1.7	)		—			—			—		—			—			(1.7	)		—
Shares issued under compensation program		1,095			—		—			—			—			—		—			—			—			—
Shares tendered for tax withholding obligations		(397	)		—		—			—			—			397		(22.5	)		—			(22.5	)		—
Repurchases of common stock		(738	)		—		—			—			—			738		(49.7	)		—			(49.7	)		—
Series A Preferred Stock dividends
Dividends - $23.75 per share		—			—		—			(21.8	)		—			—		—			—			(21.8	)		—
Dividends in excess of retained earnings		—			—		(21.8	)		21.8			—			—		—			—			—			—
Common stock dividends
Dividends - $0.35 per share		—			—		—			(80.0	)		—			—		—			—			(80.0	)		—
Dividends in excess of retained earnings		—			—		(80.0	)		80.0			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(72.2	)		(72.2	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			2.9			2.9			—
Repurchase of noncontrolling interests, net of tax		—			—		(53.1	)		—			—			—		—			(857.9	)		(911.0	)		—
Other comprehensive income (loss)		—			—		—			—			(187.5	)		—		—			—			(187.5	)		—
Net income (loss)		—			—		—			88.0			—			—		—			80.6			168.6			—
Balance, March 31, 2022		228,181		$	0.2	$	4,125.8		$	(1,734.3	)	$	(418.4	)		9,019	$	(276.3	)	$	2,320.3		$	4,017.3		$	749.7

See notes to consolidated financial statements.

8

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2023			2022
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	555.2		$	168.6
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		3.2			2.4
Compensation on equity grants		15.0			13.5
Depreciation and amortization expense		324.8			209.1
(Gain) loss on sale or disposition of assets		(1.5	)		(1.0	)
Write-downs of assets		0.9			0.5
Accretion of asset retirement obligations		1.6			1.1
Deferred income tax expense (benefit)		106.0			21.1
Equity (earnings) loss of unconsolidated affiliates		0.2			(5.6	)
Distributions of earnings received from unconsolidated affiliates		1.4			6.0
Risk management activities		(175.7	)		178.2
(Gain) loss from financing activities		—			15.8
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets		440.8			(216.2	)
Inventories		237.5			55.9
Accounts payable, accrued liabilities and other liabilities		(292.7	)		362.8
Interest payable		(46.9	)		(64.0	)
Net cash provided by operating activities		1,169.8			748.2
Cash flows from investing activities
Outlays for property, plant and equipment		(475.7	)		(204.4	)
Proceeds from sale of assets		0.2			1.0
Investments in unconsolidated affiliates		(6.2	)		(0.4	)
Return of capital from unconsolidated affiliates		1.2			6.8
Other, net		(0.3	)		—
Net cash provided by (used in) investing activities		(480.8	)		(197.0	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		—			1,805.0
Repayments of credit facilities		(290.0	)		(810.0	)
Proceeds from borrowings of commercial paper notes		14,526.8			—
Repayments of commercial paper notes		(15,230.5	)		—
Proceeds from borrowings under accounts receivable securitization facility		—			250.0
Repayments of accounts receivable securitization facility		(96.0	)		(130.0	)
Proceeds from issuance of senior notes		1,717.1			—
Redemption of senior notes		—			(480.7	)
Principal payments of finance leases		(9.4	)		(3.2	)
Costs incurred in connection with financing arrangements		(4.1	)		(10.9	)
Repurchase of shares		(85.8	)		(72.2	)
Contributions from noncontrolling interests		0.2			2.9
Distributions to noncontrolling interests		(47.3	)		(90.4	)
Repurchase of noncontrolling interests		(1,091.9	)		(926.3	)
Dividends paid to common and Series A Preferred shareholders		(85.3	)		(108.0	)
Net cash provided by (used in) financing activities		(696.2	)		(573.8	)
Net change in cash and cash equivalents		(7.2	)		(22.6	)
Cash and cash equivalents, beginning of period		219.0			158.5
Cash and cash equivalents, end of period	$	211.8		$	135.9

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 midstream infrastructure assets.

In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership”. Targa consolidated the Partnership and its subsidiaries under GAAP, and prepared the accompanying consolidated financial statements under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:

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

•the inclusion of the TRGP senior notes;

•the inclusion of the TRGP commercial paper notes;

•the inclusion of Series A Preferred Stock (“Series A Preferred”) prior to full redemption in May 2022; and

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

Our Operations

The Company is primarily engaged in the business of:

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

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

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

See Note 16 – Segment Information for certain financial information regarding our business segments.

Note 2 — Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, of a normal recurring nature and considered necessary for a fair statement of the results of the interim periods reported. All intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation. Operating results for the three months ended March 31, 2023 are not necessarily indicative of the results that may be expected for the year ending December 31, 2023.

10

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 three months ended March 31, 2023.

Recently Adopted Accounting Pronouncements

Supplier Finance Programs

In September 2022, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual and interim disclosure of the key terms of outstanding supplier finance programs and a rollforward of the related obligations. These amendments do not affect the recognition, measurement or financial statement presentation of the supplier finance program obligations. These amendments are effective for fiscal years beginning after December 15, 2022, except for the rollforward requirements, which are effective for fiscal years beginning after December 15, 2023. We maintain a supply chain finance program that allows participating suppliers to request early payment from a third-party financial institution of invoices that we confirm as valid. Under this program, we make payments to the third-party financial institution monthly. We adopted the amendments on January 1, 2023, with no material impact on our consolidated financial statements.

Note 4 – Acquisitions and Divestitures

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

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

In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture (the “Grand Prix Transaction”) for aggregate consideration of $1.05 billion in cash and a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of the interest in Grand Prix. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $490.7 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the Grand Prix Transaction resulted in a $457.3 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

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Note 5 — Property, Plant and Equipment and Intangible Assets

	March 31, 2023			December 31, 2022			Estimated Useful Lives (In Years)
Gathering systems	$	10,518.6		$	10,403.1		5 to 20
Processing and fractionation facilities		7,590.3			7,421.2		5 to 25
Terminaling and storage facilities		1,346.7			1,341.6		5 to 25
Transportation assets		2,989.1			2,919.3		10 to 50
Other property, plant and equipment		395.0			387.6		3 to 50
Land		173.3			163.3		—
Construction in progress		1,085.1			1,011.0		—
Finance lease right-of-use assets		284.3			266.1		5 to 14
Property, plant and equipment		24,382.4			23,913.2
Accumulated depreciation, amortization and impairment		(9,912.4	)		(9,698.6	)
Property, plant and equipment, net	$	14,470.0		$	14,214.6
Intangible assets		4,379.7			4,379.7		10 to 20
Accumulated amortization and impairment		(1,741.1	)		(1,645.1	)
Intangible assets, net	$	2,638.6		$	2,734.6

During the three months ended March 31, 2023 and 2022, depreciation expense was $228.8 million and $181.1 million, respectively.

Intangible Assets

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

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

The changes in our intangible assets are as follows:

	March 31, 2023
Balance at beginning of period	$	2,734.6
Amortization		(96.0	)
Balance at end of period	$	2,638.6

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Note 6 — Debt Obligations

	March 31, 2023			December 31, 2022
Current:
Partnership accounts receivable securitization facility, due September 2023 (1)	$	704.0		$	800.0
Finance lease liabilities		35.0			34.3
Current debt obligations		739.0			834.3
Long-term:
Term loan facility, variable rate, due July 2025		1,500.0			1,500.0
TRGP senior revolving credit facility, variable rate, due February 2027 (2)		305.0			1,298.7
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027		750.0			750.0
4.200% fixed rate, due February 2033		750.0			750.0
6.125% fixed rate, due March 2033 (3)		900.0			—
4.950% fixed rate, due April 2052		750.0			750.0
6.250% fixed rate, due July 2052		500.0			500.0
6.500% fixed rate, due February 2053 (3)		850.0			—
Unamortized discount		(41.0	)		(8.4	)
Senior unsecured notes issued by the Partnership: (4)
6.500% fixed rate, due July 2027		705.2			705.2
5.000% fixed rate, due January 2028		700.3			700.3
6.875% fixed rate, due January 2029		679.3			679.3
5.500% fixed rate, due March 2030		949.6			949.6
4.875% fixed rate, due February 2031		1,000.0			1,000.0
4.000% fixed rate, due January 2032		1,000.0			1,000.0
		11,298.4			10,574.7
Debt issuance costs, net of amortization		(67.7	)		(65.6	)
Finance lease liabilities		208.9			193.0
Long-term debt		11,439.6			10,702.1
Total debt obligations	$	12,178.6		$	11,536.4
Irrevocable standby letters of credit: (2)
Letters of credit outstanding under the TRGP senior revolving credit facility	$	33.2		$	33.2
	$	33.2		$	33.2

(1)The Partnership's accounts receivable securitization facility (the “Securitization Facility”) provides up to $800 million of borrowing capacity. As of March 31, 2023, the Partnership had $704.0 million of qualifying receivables.

(2)We maintain an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our $2.75 billion TRGP senior revolving credit facility (the “TRGP Revolver”) equal to the aggregate amount outstanding under the Commercial Paper Program. As of March 31, 2023, the TRGP Revolver had no borrowings outstanding and the Commercial Paper Program had $305.0 million borrowings outstanding, resulting in approximately $2.4 billion of available liquidity, after accounting for outstanding letters of credit.

(3)In January 2023, we completed an underwritten public offering of (i) $900.0 million aggregate principal amount of our 6.125% Senior Notes due 2033 (the “6.125% Notes”) and (ii) $850.0 million aggregate principal amount of our 6.500% Senior Notes due 2053 (the “6.500% Notes”), resulting in net proceeds of approximately $1.7 billion.

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

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2023:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRGP Revolver and Commercial Paper Program	5.2% - 5.9%	5.4%
Securitization Facility	5.2% - 5.4%	5.3%
Term Loan Facility	5.8% - 6.3%	6.0%

Compliance with Debt Covenants

As of March 31, 2023, we were in compliance with the covenants contained in our various debt agreements.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of March 31, 2023, $5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

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Debt Obligations

Commercial Paper Program

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

Senior Unsecured Notes Issuances

In January 2023, we completed an underwritten public offering of the 6.125% Notes and the 6.500% Notes, resulting in net proceeds of approximately $1.7 billion. The 6.125% Notes and the 6.500% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 6.125% Notes and the 6.500% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Fifth Supplemental Indenture, dated as of January 3, 2023, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Note 7 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following:

	March 31, 2023		December 31, 2022
Deferred revenue	$	204.5	$	198.8
Asset retirement obligations		99.7		97.9
Operating lease liabilities		27.2		28.6
Other liabilities		15.0		15.9
Total other long-term liabilities	$	346.4	$	341.2

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 March 31, 2023 and December 31, 2022, was $204.5 million and $198.8 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. See Note 12 – Contingencies.

Deferred revenue includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems. Deferred revenue also includes contributions in aid of construction received from customers for which revenue is recognized over the expected contract term.

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Note 8 — Common Stock and Related Matters

Common Share Repurchase Program

In October 2020, our board of directors approved a share repurchase program (the “2020 Share Repurchase Program”) for the repurchase of up to $500.0 million of our outstanding common stock. In May 2023, our board of directors approved a new share repurchase program (the “2023 Share Repurchase Program” and, together with the 2020 Share Repurchase Program, the “Share Repurchase Programs”) for the repurchase of up to $1.0 billion of our outstanding common stock. We may discontinue either Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

For the three months ended March 31, 2023, we repurchased 724,140 shares of our common stock at a weighted average per share price of $71.82 for a total net cost of $52.0 million. For the three months ended March 31, 2022, we repurchased 737,799 shares of our common stock at a weighted average per share price of $67.37 for a total net cost of $49.7 million. As of March 31, 2023, there was $91.8 million remaining under the 2020 Share Repurchase Program.

Common Stock Dividends

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

The following table details the dividends declared and/or paid by us to common shareholders for the three months ended March 31, 2023:

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
March 31, 2023	May 15, 2023	$		114.7	$		113.0	$		1.7	$		0.50000
December 31, 2022	February 15, 2023			80.5			79.3			1.2			0.35000

f

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

Note 9 — Earnings per Common Share

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 March 31,
	2023		2022
	(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.	$	497.0	$	88.0
Less: Premium on repurchase of noncontrolling interests, net of tax (1)		490.7		53.1
Less: Dividends on Series A Preferred Stock (2)		—		21.8
Net income (loss) attributable to common shareholders for basic earnings per share	$	6.3	$	13.1
Weighted average shares outstanding - basic		226.4		228.5
Dilutive effect of unvested stock awards		2.9		3.9
Weighted average shares outstanding - diluted		229.3		232.4
Net income (loss) available per common share - basic	$	0.03	$	0.06
Net income (loss) available per common share - diluted	$	0.03	$	0.06

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

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

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 March 31,
	2023		2022
Unvested restricted stock awards		0.1		0.1
Series A Preferred (1)		—		44.3

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

Note 10 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues as current income.

At March 31, 2023, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2023		2024		2025		2026		2027
Natural Gas	Swaps	MMBtu/d		161,545		105,377		39,366		—		—
Natural Gas	Basis Swaps	MMBtu/d		609,255		328,298		256,658		102,500		25,000
NGL	Swaps	Bbl/d		41,286		24,699		11,941		—		—
NGL	Futures	Bbl/d		6,909		2,437		—		—		—
Condensate	Swaps	Bbl/d		6,273		3,832		2,053		—		—

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

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

		Fair Value as of March 31, 2023					Fair Value as of December 31, 2022
	Balance Sheet	Derivative		Derivative			Derivative		Derivative
	Location	Assets		Liabilities			Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	134.9	$	(57.9	)	$	158.7	$	(93.8	)
	Long-term		33.7		(8.8	)		24.2		(30.9	)
Total derivatives designated as hedging instruments		$	168.6	$	(66.7	)	$	182.9	$	(124.7	)
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	11.6	$	(98.7	)	$	21.2	$	(226.3	)
	Long-term		2.5		(53.6	)		0.3		(109.2	)
Total derivatives not designated as hedging instruments		$	14.1	$	(152.3	)	$	21.5	$	(335.5	)
Total current position		$	146.5	$	(156.6	)	$	179.9	$	(320.1	)
Total long-term position			36.2		(62.4	)		24.5		(140.1	)
Total derivatives		$	182.7	$	(219.0	)	$	204.4	$	(460.2	)

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The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation							Pro Forma Net Presentation
March 31, 2023		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	132.2	$	(154.2	)	$	1.8	$	55.7	$	(75.9	)
	Counterparties without offsetting positions - assets		14.3		—			—		14.3		—
	Counterparties without offsetting positions - liabilities		—		(2.4	)		—		—		(2.4	)
			146.5		(156.6	)		1.8		70.0		(78.3	)
Long-Term Position
	Counterparties with offsetting positions or collateral		33.4		(62.4	)		10.9		10.6		(28.7	)
	Counterparties without offsetting positions - assets		2.8		—			—		2.8		—
	Counterparties without offsetting positions - liabilities		—		—			—		—		—
			36.2		(62.4	)		10.9		13.4		(28.7	)
Total Derivatives
	Counterparties with offsetting positions or collateral		165.6		(216.6	)		12.7		66.3		(104.6	)
	Counterparties without offsetting positions - assets		17.1		—			—		17.1		—
	Counterparties without offsetting positions - liabilities		—		(2.4	)		—		—		(2.4	)
		$	182.7	$	(219.0	)	$	12.7	$	83.4	$	(107.0	)
		Gross Presentation							Pro Forma Net Presentation
December 31, 2022		Asset		Liability			Collateral		Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	162.2	$	(316.7	)	$	12.2	$	27.2	$	(169.5	)
	Counterparties without offsetting positions - assets		17.7		—			—		17.7		—
	Counterparties without offsetting positions - liabilities		—		(3.4	)		—		—		(3.4	)
			179.9		(320.1	)		12.2		44.9		(172.9	)
Long-Term Position
	Counterparties with offsetting positions or collateral		24.5		(137.4	)		22.4		7.3		(97.8	)
	Counterparties without offsetting positions - assets		—		—			—		—		—
	Counterparties without offsetting positions - liabilities		—		(2.7	)		—		—		(2.7	)
			24.5		(140.1	)		22.4		7.3		(100.5	)
Total Derivatives
	Counterparties with offsetting positions or collateral		186.7		(454.1	)		34.6		34.5		(267.3	)
	Counterparties without offsetting positions - assets		17.7		—			—		17.7		—
	Counterparties without offsetting positions - liabilities		—		(6.1	)		—		—		(6.1	)
		$	204.4	$	(460.2	)	$	34.6	$	52.2	$	(273.4	)

Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within Other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association (“ISDA”) agreements, which govern the key terms with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured. As of March 31, 2023, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $103.3 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 Investors Service, Inc. and Standard & Poor’s Financial Services LLC, as defined in our ISDAs, we estimate that as of March 31, 2023, we would not be required to post collateral to certain counterparties per the terms of our ISDAs.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $36.3 million as of March 31, 2023. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended March 31,
Hedging Relationships	2023		2022
Commodity contracts	$	83.9	$	(387.1	)

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	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended March 31,
Location of Gain (Loss)	2023		2022
Revenues	$	45.2	$	(145.7	)

Based on valuations as of March 31, 2023, we expect to reclassify commodity hedge-related deferred gains of $102.0 million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with $75.2 million of gains to be reclassified over the next twelve months.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three months ended March 31, 2023, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward prices, as compared to our positions.

	Location of Gain (Loss)	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2023		2022
Commodity contracts	Revenue	$	178.0	$	(177.0	)

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 assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

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

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2023, a net liability position of $36.3 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $184.4 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 $112.0 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. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

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

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

Fair Value Hierarchy

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

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

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

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

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

	March 31, 2023
	Carrying		Fair Value
	Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	$	182.0	$	182.0	$	—	$	182.0	$	—
Liabilities from commodity derivative contracts (1)		218.3		218.3		—		218.3		—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		211.8		211.8		—		—		—
TRGP Revolver and Commercial Paper Program		305.0		305.0		—		305.0		—
TRGP Senior unsecured notes		4,459.0		4,298.8		—		4,298.8		—
Term Loan Facility		1,500.0		1,500.0		—		1,500.0		—
Partnership's Senior unsecured notes		5,034.4		4,849.8		—		4,849.8		—
Securitization Facility		704.0		704.0		—		704.0		—

	December 31, 2022
	Carrying		Fair Value
	Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	$	201.6	$	201.6	$	—	$	201.6	$	—
Liabilities from commodity derivative contracts (1)		457.4		457.4		—		457.4		—
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		219.0		219.0		—		—		—
TRGP Revolver and Commercial Paper Program		1,298.7		1,298.7		—		1,298.7		—
TRGP Senior unsecured notes		2,741.6		2,452.6		—		2,452.6		—
Term Loan Facility		1,500.0		1,500.0		—		1,500.0		—
Partnership's Senior unsecured notes		5,034.4		4,711.3		—		4,711.3		—
Securitization Facility		800.0		800.0		—		800.0		—

(1)The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 10 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

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

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

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

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing, and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. As of March 31, 2023 and December 31, 2022, we had no derivative contracts categorized as Level 3.

Note 12 — Contingencies

Legal Proceedings

We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including, but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.

On December 26, 2018, Vitol filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached the Splitter Agreement, which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company appealed the award in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We have filed a petition for review with the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the award through March 31, 2023, if accrued, would have been approximately $45.8 million.

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Note 13 — Revenue

Fixed consideration allocated to remaining performance obligations

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 16 years.

	2023		2024		2025 and after
Fixed consideration to be recognized as of March 31, 2023	$	346.6	$	457.9	$	2,238.3

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

For disclosures related to disaggregated revenue, see Note 16 – Segment Information.

Note 14 — Income Taxes

We record income taxes using an estimated annual effective tax rate and recognize specific events discretely as they occur. We recorded income tax expense of $110.3 million and $22.9 million during the three months ended March 31, 2023 and 2022, respectively. Our effective tax rate for the three months ended March 31, 2023 is lower than the U.S. corporate statutory rate of 21% primarily due to the release of a portion of our state valuation allowances in addition to income allocated to noncontrolling interests that is not taxable. The effective tax rate for the three months ended March 31, 2022 was lower than the U.S. corporate statutory rate of 21% primarily due to the release of a portion of our federal valuation allowances in addition to income allocated to noncontrolling interests that is not taxable to the Company.

We regularly evaluate the realizable tax benefits of deferred tax assets and record a valuation allowance, if required, based on an estimate of the amount of deferred tax assets that we believe does not meet the more-likely-than-not criteria of being realized. As of March 31, 2023, our valuation allowance was $13.4 million, a decrease of $23.5 million from December 31, 2022. After the change in valuation allowance, we have a net deferred tax liability of $298.3 million.

We are subject to tax in the U.S. and various state jurisdictions. Additionally, we are subject to periodic audits and reviews by U.S. federal and state taxing authorities. As of March 31, 2023, Internal Revenue Service (“IRS”) examinations are currently in process for the 2019 and 2020 taxable years of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We are not aware of any potential audit findings that would give rise to adjustments to taxable income and do not anticipate material changes related to these audits.

Note 15 — Supplemental Cash Flow Information

	Three Months Ended March 31,
	2023			2022
Cash:
Interest paid, net of capitalized interest (1)	$	211.6		$	151.3
Income taxes (received) paid, net		0.1			(0.2	)
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		(21.4	)		(41.9	)
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests	$	8.8		$	(18.2	)

(1)Interest capitalized on major projects was $6.7 million and $2.4 million for the three months ended March 31, 2023 and 2022.

Note 16 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets

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used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes Grand Prix, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2023
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	287.9	$	3,561.3	$	175.8	$	—		$	4,025.0
Fees from midstream services		320.4		175.1		—		—			495.5
		608.3		3,736.4		175.8		—			4,520.5
Intersegment revenues
Sales of commodities		1,347.0		78.2		—		(1,425.2	)		—
Fees from midstream services		0.5		10.8		—		(11.3	)		—
		1,347.5		89.0		—		(1,436.5	)		—
Revenues	$	1,955.8	$	3,825.4	$	175.8	$	(1,436.5	)	$	4,520.5
Operating margin (1)	$	538.4	$	529.1	$	175.8
Other financial information:
Total assets (2)	$	12,199.9	$	6,558.4	$	4.2	$	263.0		$	19,025.5
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	269.5	$	176.6	$	—	$	8.2		$	454.3

	Three Months Ended March 31, 2022
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	134.6	$	4,609.9	$	(178.3	)	$	—		$	4,566.2
Fees from midstream services		210.4		182.5		—			—			392.9
		345.0		4,792.4		(178.3	)		—			4,959.1
Intersegment revenues
Sales of commodities		2,030.6		124.3		—			(2,154.9	)		—
Fees from midstream services		0.3		10.8		—			(11.1	)		—
		2,030.9		135.1		—			(2,166.0	)		—
Revenues	$	2,375.9	$	4,927.5	$	(178.3	)	$	(2,166.0	)	$	4,959.1
Operating margin (1)	$	397.6	$	352.1	$	(178.3	)
Other financial information:
Total assets (2)	$	7,932.2	$	7,214.8	$	1.6		$	146.8		$	15,295.4
Goodwill	$	45.2	$	—	$	—		$	—		$	45.2
Capital expenditures	$	133.0	$	25.2	$	—		$	4.3		$	162.5

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

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

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

	Three Months Ended March 31,
	2023		2022
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	816.1	$	964.3
NGL		2,864.5		3,806.5
Condensate and crude oil		121.2		118.1
		3,801.8		4,888.9
Non-customer revenue:
Derivative activities - Hedge		45.2		(145.7	)
Derivative activities - Non-hedge (1)		178.0		(177.0	)
		223.2		(322.7	)
Total sales of commodities		4,025.0		4,566.2
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		315.5		206.0
NGL transportation, fractionation and services		56.1		65.8
Storage, terminaling and export		108.8		100.9
Other		15.1		20.2
Total fees from midstream services		495.5		392.9
Total revenues	$	4,520.5	$	4,959.1

(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 March 31,
	2023			2022
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	538.4		$	397.6
Logistics and Transportation operating margin		529.1			352.1
Other operating margin		175.8			(178.3	)
Depreciation and amortization expense		(324.8	)		(209.1	)
General and administrative expense		(82.4	)		(67.1	)
Other operating income (expense)		0.6			0.5
Interest expense, net		(168.0	)		(93.6	)
Equity earnings (loss)		(0.2	)		5.6
Gain (loss) from financing activities		—			(15.8	)
Other, net		(3.0	)		(0.4	)
Income (loss) before income taxes	$	665.5		$	191.5

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

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

Overview

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

Our Operations

We are engaged primarily in the business of:

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

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

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

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

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

Recent Developments

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

Permian Midland Processing Expansions

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

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

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Permian Delaware Processing Expansions

•In February 2022, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Midway plant”). The Midway plant is expected to begin operations in the second quarter of 2023. In conjunction with the commencement of operations of the Midway plant, we expect to idle an existing 165 MMcf/d cryogenic natural gas processing plant.

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

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

Fractionation Expansion

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

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

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

NGL Pipeline Expansion

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

Acquisitions

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

Capital Allocation

For the three months ended March 31, 2023, we repurchased 724,140 shares of our common stock at a weighted average per share price of $71.82 for a total net cost of $52.0 million. There was $91.8 million remaining under our $500 million common share repurchase program (the “2020 Share Repurchase Program”) as of March 31, 2023.

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

In May 2023, our Board of Directors authorized a new $1.0 billion common share repurchase program (the “2023 Share Repurchase Program” and, together with the 2020 Share Repurchase Program, the “Share Repurchase Programs”). The amount authorized under the 2023 Share Repurchase Program is in addition to the amount remaining under the 2020 Share Repurchase Program. We may discontinue either Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

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Financing Activities

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

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

Corporation Tax Matters

As of March 31, 2023, Internal Revenue Service (“IRS”) examinations are currently in process for the 2019 and 2020 taxable years of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S federal income tax purposes. We are responding to the information requests from the IRS with respect to these audits. We are not aware of any potential audit findings that would give rise to adjustments to taxable income and do not anticipate material changes related to these audits.

On August 16, 2022, President Biden signed into law the IRA which, among other things, introduced a corporate alternative minimum tax (the “CAMT”), imposed a 1% excise tax on stock buybacks, and provided tax incentives to promote clean energy. Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1.0 billion.

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

Recent Accounting Pronouncements

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

How We Evaluate Our Operations

The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

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

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

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Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

Capital spending associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Non-GAAP Measures

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

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Adjusted Operating Margin

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

Gathering and Processing adjusted operating margin consists primarily of:

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

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

Logistics and Transportation adjusted operating margin consists primarily of:

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

•system product gains and losses; and

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

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

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

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

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

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

Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”

Adjusted EBITDA

We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

Distributable Cash Flow and Adjusted Free Cash Flow

We define distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). We define adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

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Our Non-GAAP Financial Measures

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

	Three Months Ended March 31,
	2023			2022
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	497.0		$	88.0
Interest (income) expense, net		168.0			93.6
Income tax expense (benefit)		110.3			22.9
Depreciation and amortization expense		324.8			209.1
(Gain) loss on sale or disposition of assets		(1.5	)		(1.0	)
Write-down of assets		0.9			0.5
(Gain) loss from financing activities (1)		—			15.8
Equity (earnings) loss		0.2			(5.6	)
Distributions from unconsolidated affiliates and preferred partner interests, net		2.6			12.5
Compensation on equity grants		15.0			13.5
Risk management activities		(175.7	)		178.2
Noncontrolling interests adjustments (2)		(1.0	)		(1.7	)
Adjusted EBITDA	$	940.6		$	625.8
Interest expense on debt obligations (3)		(165.1	)		(91.7	)
Maintenance capital expenditures, net (4)		(41.8	)		(37.7	)
Cash taxes		(4.3	)		(1.8	)
Distributable Cash Flow	$	729.4		$	494.6
Growth capital expenditures, net (4)		(415.4	)		(121.4	)
Adjusted Free Cash Flow	$	314.0		$	373.2

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

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

(3)Excludes amortization of interest expense.

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

Consolidated Results of Operations

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

	Three Months Ended March 31,
	2023			2022			2023 vs. 2022
	(In millions)
Revenues:
Sales of commodities	$	4,025.0		$	4,566.2		$	(541.2	)		(12	%)
Fees from midstream services		495.5			392.9			102.6			26	%
Total revenues		4,520.5			4,959.1			(438.6	)		(9	%)
Product purchases and fuel		3,019.0			4,204.1			(1,185.1	)		(28	%)
Operating expenses		258.2			183.5			74.7			41	%
Depreciation and amortization expense		324.8			209.1			115.7			55	%
General and administrative expense		82.4			67.1			15.3			23	%
Other operating (income) expense		(0.6	)		(0.5	)		(0.1	)		20	%
Income (loss) from operations		836.7			295.8			540.9			183	%
Interest expense, net		(168.0	)		(93.6	)		(74.4	)		79	%
Equity earnings (loss)		(0.2	)		5.6			(5.8	)		(104	%)
Gain (loss) from financing activities		—			(15.8	)		15.8			100	%
Other, net		(3.0	)		(0.5	)		(2.5	)	NM
Income tax (expense) benefit		(110.3	)		(22.9	)		(87.4	)	NM
Net income (loss)		555.2			168.6			386.6			229	%
Less: Net income (loss) attributable to noncontrolling interests		58.2			80.6			(22.4	)		(28	%)
Net income (loss) attributable to Targa Resources Corp.		497.0			88.0			409.0		NM
Premium on repurchase of noncontrolling interests, net of tax		490.7			53.1			437.6		NM
Dividends on Series A Preferred Stock		—			21.8			(21.8	)		(100	%)
Net income (loss) attributable to common shareholders	$	6.3		$	13.1		$	(6.8	)		(52	%)
Financial data:
Adjusted EBITDA (1)	$	940.6		$	625.8		$	314.8			50	%
Distributable cash flow (1)		729.4			494.6			234.8			47	%
Adjusted free cash flow (1)		314.0			373.2			(59.2	)		(16	%)

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

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

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Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($1,769.2 million), partially offset by higher NGL, natural gas and condensate volumes ($682.1 million) and the favorable impact of hedges ($546.0 million).

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

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

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

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

The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and South Texas, the shortening of depreciable lives of certain assets that have been, or will be, idled and the impact of system expansions on our asset base.

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

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

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

The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in 2023 compared to 2022.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower income allocation to noncontrolling interest holders in the Carnero Joint Venture.

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

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

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:
March 31, 2023	$	538.4	$	529.1	$	175.8
March 31, 2022		397.6		352.1		(178.3	)

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Gathering and Processing Segment

	Three Months Ended March 31,
	2023			2022		2023 vs. 2022
		(In millions, except operating statistics and price amounts)
Operating margin	$		538.4	$	397.6	$	140.8		35	%
Operating expenses			181.4		116.6		64.8		56	%
Adjusted operating margin	$		719.8	$	514.2	$	205.6		40	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			2,348.6		2,075.1		273.5		13	%
Permian Delaware (5)			2,495.1		977.0		1,518.1		155	%
Total Permian			4,843.7		3,052.1		1,791.6		59	%
SouthTX (6)			355.9		162.1		193.8		120	%
North Texas			195.5		175.3		20.2		12	%
SouthOK (6)			383.9		407.3		(23.4	)	(6	%)
WestOK			204.1		202.5		1.6		1	%
Total Central			1,139.4		947.2		192.2		20	%
Badlands (6) (7)			131.8		125.0		6.8		5	%
Total Field			6,114.9		4,124.3		1,990.6		48	%
Coastal			509.2		602.1		(92.9	)	(15	%)
Total			6,624.1		4,726.4		1,897.7		40	%
NGL production, MBbl/d (3)
Permian Midland (4)			335.0		300.8		34.2		11	%
Permian Delaware (5)			342.7		129.8		212.9		164	%
Total Permian			677.7		430.6		247.1		57	%
SouthTX (6)			38.4		20.3		18.1		89	%
North Texas			23.0		19.2		3.8		20	%
SouthOK (6)			38.8		50.5		(11.7	)	(23	%)
WestOK			13.1		14.9		(1.8	)	(12	%)
Total Central			113.3		104.9		8.4		8	%
Badlands (6)			15.4		14.7		0.7		5	%
Total Field			806.4		550.2		256.2		47	%
Coastal			36.2		37.1		(0.9	)	(2	%)
Total			842.6		587.3		255.3		43	%
Crude oil, Badlands, MBbl/d			110.6		122.7		(12.1	)	(10	%)
Crude oil, Permian, MBbl/d			25.5		30.6		(5.1	)	(17	%)
Natural gas sales, BBtu/d (3)			2,572.5		2,126.3		446.2		21	%
NGL sales, MBbl/d (3)			459.1		424.8		34.3		8	%
Condensate sales, MBbl/d			19.8		14.4		5.4		38	%
Average realized prices - inclusive of hedges (8):
Natural gas, $/MMBtu			2.63		4.09		(1.46	)	(36	%)
NGL, $/gal			0.52		0.79		(0.27	)	(34	%)
Condensate, $/Bbl			66.34		75.72		(9.38	)	(12	%)

(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.

(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)Includes operations from the acquisition of certain assets in the Delaware Basin for the period effective August 1, 2022.

(6)Operations include facilities that are not wholly owned by us. SouthTX operating statistics include the impact of the acquisition of certain assets in South Texas for the period effective April 21, 2022.

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

(8)Average realized prices 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.

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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 March 31, 2023								Three Months Ended March 31, 2022
	(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)		19.7	$	1.35		$	26.5			17.5	$	(1.78	)	$	(31.2	)
NGL (MMgal)		184.1		0.05			9.5			170.4		(0.46	)		(78.0	)
Crude oil (MBbl)		0.6		(4.67	)		(2.8	)		0.5		(39.40	)		(19.7	)
						$	33.2							$	(128.9	)

(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 March 31, 2023 Compared to Three Months Ended March 31, 2022

The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy and Red Hills VI plants during the third quarter of 2022 and continued strong producer activity. Natural gas inlet volumes in the Central region increased primarily due to the acquisition of certain assets in South Texas during the second quarter of 2022. The decrease in volumes in the Coastal region was attributable to lower production.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and third quarters of 2022. Additionally, higher volumes in the Permian, the addition of the Legacy and Red Hills VI plants in the third quarter of 2022 and inflation impacts resulted in increased costs.

Logistics and Transportation Segment

	Three Months Ended March 31,
	2023		2022		2023 vs. 2022
	(In millions, except operating statistics)
Operating margin	$	529.1	$	352.1	$	177.0	50%
Operating expenses		76.5		66.9		9.6	14%
Adjusted operating margin	$	605.6	$	419.0	$	186.6	45%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)		536.8		459.7		77.1	17%
Fractionation volumes		758.8		702.8		56.0	8%
Export volumes (3)		373.4		340.8		32.6	10%
NGL sales		1,007.6		872.8		134.8	15%

(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.

(2)Represents the total quantity of mixed NGLs that earn a transportation margin.

(3)Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

The increase in adjusted operating margin was due to higher marketing margin, higher pipeline transportation and fractionation margin, and higher LPG export margin. Marketing margin increased due to greater optimization opportunities. Pipeline transportation and fractionation volumes benefited primarily from higher supply volumes from our Permian Gathering and Processing systems. LPG export margin increased due to higher volumes and fees.

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

Other

	Three Months Ended March 31,
	2023		2022			2023 vs. 2022
	(In millions)
Operating margin	$	175.8	$	(178.3	)	$	354.1
Adjusted operating margin	$	175.8	$	(178.3	)	$	354.1

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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 March 31, 2023, inclusive of our consolidated joint venture accounts, we had $211.8 million of Cash and cash equivalents on our Consolidated Balance Sheets. We believe our cash positions, our cash flows from operating activities, our free cash flow after dividends and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below. Our liquidity and capital resources are managed on a consolidated basis.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments.”

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, Commercial Paper Program, Partnership's accounts receivable securitization facility (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. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of March 31, 2023, was:

	Consolidated Total
	(In millions)
Cash on hand (1)	$	211.8
Total availability under the Securitization Facility		704.0
Total availability under the TRGP Revolver and Commercial Paper Program		2,750.0
		3,665.8
Less: Outstanding borrowings under the Securitization Facility		(704.0	)
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program		(305.0	)
Outstanding letters of credit under the TRGP Revolver		(33.2	)
Total liquidity	$	2,623.6

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

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

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of March 31, 2023, we had $33.2 million letters of credit outstanding under the TRGP Revolver. They reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

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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.

Working capital as of March 31, 2023 decreased $117.7 million compared to December 31, 2022. The decrease was primarily due to lower NGL inventory, lower net receivables and product purchases and fuel payables as a result of lower commodity prices, partially offset by a decrease in the current liability position of our derivative contracts and lower net borrowings on the Securitization Facility.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRGP Revolver, Commercial Paper Program, Securitization Facility, and proceeds from debt and equity offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelve months.

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 January 2023, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of the 6.125% Notes and the 6.500% Notes, resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, 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 additional information about our debt-related transactions, see Note 6 - 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.”

Compliance with Debt Covenants

As of March 31, 2023, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow

Cash Flows from Operating Activities

Three Months Ended March 31,
2023		2022		2023 vs. 2022
(In millions)
$	1,169.8	$	748.2	$	421.6

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

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The increase in net cash provided by operations was primarily due to higher collections from customers and hedge transactions, partially offset by an increase in payments for product purchases and fuel.

Cash Flows from Investing Activities

Three Months Ended March 31,
2023			2022			2023 vs. 2022
(In millions)
$	(480.8	)	$	(197.0	)	$	(283.8	)

The increase in net cash used in investing activities was primarily due to higher outlays for property, plant and equipment resulting from construction activities in the Permian region and Mont Belvieu, Texas.

Cash Flows from Financing Activities

	Three Months Ended March 31,
	2023			2022
	(In millions)
Source of Financing Activities, net
Debt, including financing costs	$	613.9		$	620.2
Repurchase of noncontrolling interests		(1,091.9	)		(926.3	)
Dividends		(85.3	)		(108.0	)
Contributions from (distributions to) noncontrolling interests		(47.1	)		(87.5	)
Repurchase of shares		(85.8	)		(72.2	)
Net cash provided by (used in) financing activities	$	(696.2	)	$	(573.8	)

The increase in net cash used in financing activities was primarily due to higher repurchases of noncontrolling interests and common stock in 2023 as compared to 2022, partially offset by lower distributions to noncontrolling interests and dividends paid in 2023. The decrease in dividends paid was due to the redemption of Series A Preferred in May 2022.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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

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

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

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

Summarized Combined Balance Sheet Information
	March 31, 2023			December 31, 2022
	(In millions)
ASSETS
Current assets	$	806.5		$	1,386.9
Current assets - affiliates		9.2			6.0
Long-term assets		11,017.6			10,163.5
Long-term assets - affiliates		10.5			10.5
Total assets	$	11,843.8		$	11,566.9
LIABILITIES AND OWNERS' EQUITY
Current liabilities	$	1,292.9		$	1,779.3
Current liabilities - affiliates		35.7			64.2
Long-term liabilities		11,936.6			11,315.6
Targa Resources Corp. stockholders' equity		(1,421.4	)		(1,592.2	)
Total liabilities and owners' equity	$	11,843.8		$	11,566.9
Summarized Combined Statement of Operations Information
				Three Months Ended
				March 31, 2023
				(In millions)
Revenues				$	4,445.2
Operating income (loss)					720.3
Net income (loss)					461.1

Common Stock Dividends

The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2023:

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
March 31, 2023	May 15, 2023	$		114.7	$		113.0	$		1.7	$		0.50000
December 31, 2022	February 15, 2023			80.5			79.3			1.2			0.35000

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

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.

Capital Expenditures

The following table details cash outlays for capital projects for the three months ended March 31, 2023 and 2022:

	Three Months Ended March 31,
	2023		2022
	(In millions)
Capital expenditures:
Growth (1)	$	410.3	$	123.3
Maintenance (2)		44.0		39.2
Gross capital expenditures		454.3		162.5
Change in capital project payables and accruals, net		21.4		41.9
Cash outlays for capital projects	$	475.7	$	204.4

(1)Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $415.4 million and $121.4 million for the three months ended March 31, 2023 and 2022.

(2)Maintenance capital expenditures, net of contributions from noncontrolling interests, were $41.8 million and $37.7 million for the three months ended March 31, 2023 and 2022.

The increase in total growth capital expenditures was primarily due to system expansions in the Permian region in response to forecasted production growth and higher activity levels, and expansions in our downstream business. The increase in total maintenance capital expenditures was primarily due to our growing infrastructure footprint.

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With our announced natural gas processing additions currently under construction in the Permian region, coupled with the construction of our Daytona NGL Pipeline and Train 9 and Train 10 fractionators in Mont Belvieu, we currently estimate that in 2023 we will invest between $2.0 to $2.2 billion in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2023 maintenance capital expenditures, net of noncontrolling interests, will be approximately $175 million.

Off-Balance Sheet Arrangements

As of March 31, 2023, there were $251.4 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 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.

Crude oil, NGL and natural gas prices are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2027. 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. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2023, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

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

A majority of these commodity price hedges are documented pursuant to a standard International 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 March 31, 2023:

	Fair Value			Result of 10% Price Decrease			Result of 10% Price Increase
	(In millions)
Natural gas	$	(69.1	)	$	(12.8	)	$	(125.4	)
NGLs		37.6			103.1			(27.7	)
Crude oil		(4.8	)		21.7			(31.3	)
Total	$	(36.3	)	$	112.0		$	(184.4	)

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.

During the three months ended March 31, 2023 and 2022, our operating revenues increased (decreased) by $223.2 million and $(322.7) million 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 $255.8 million at December 31, 2022 to a net liability position of $36.3 million at March 31, 2023.

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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, the Securitization Facility, and the Term Loan Facility. As of March 31, 2023, 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, the Securitization Facility and the Term Loan Facility will also increase. As of March 31, 2023, we had $2.5 billion 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 $25.1 million based on our March 31, 2023 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 would reduce our maximum loss due to counterparty credit risk by $46.0 million as of March 31, 2023. The range of losses attributable to our individual counterparties as of March 31, 2023 would be between $0.1 million and $32.4 million, depending on the counterparty in default.

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 doubtful accounts was $2.5 million and $2.2 million as of March 31, 2023 and December 31, 2022, respectively.

During the three months ended March 31, 2023, no customer comprised 10% or greater of our consolidated revenues. During the three months ended March 31, 2022, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 10% 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2023, 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.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended March 31, 2023, 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.

On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company appealed the award in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We have filed a petition for review with the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the award through March 31, 2023, if accrued, would have been approximately $45.8 million.

Additional 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 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)
January 1, 2023 - January 31, 2023		626,928	$	74.78		189,147	$	129,760
February 1, 2023 - February 28, 2023		163	$	76.64		—	$	129,760
March 1, 2023 - March 31, 2023		546,237	$	71.15		534,993	$	91,752

(1)Includes 724,140 shares repurchased under the 2020 Share Repurchase Program, as well as 449,188 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 the fourth quarter of 2020, our board of directors approved the 2020 Share Repurchase Program for the repurchase of up to $500.0 million of our outstanding common stock. In May 2023, our board of directors approved the 2023 Share Repurchase Program for the repurchase of up to $1.0 billion of our outstanding common stock. We may discontinue either Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

Item 3. Defaults Upon Senior Securities.

Not applicable.

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Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

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)).
3.4	Second Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed on May 5, 2022 (File No. 001-34991)).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
4.2	Fifth Supplemental Indenture, dated as of January 9, 2023, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Current Report on Form 8-K filed January 9, 2023 (File No. 001-34991)).
4.3	Form of Notes (included in Exhibit 4.2 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K filed January 9, 2023 (File No. 001-34991)).
4.4*	Sixth Supplemental Indenture, dated as of April 12, 2023, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee.
4.5*	Supplemental Indenture dated April 12, 2023 to Indenture dated October 17, 2017 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.6*	Supplemental Indenture dated April 12, 2023 to Indenture dated January 17, 2019 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.7*	Supplemental Indenture dated April 12, 2023 to Indenture dated November 27, 2019 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.8*	Supplemental Indenture dated April 12, 2023 to Indenture dated August 18, 2020 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9*	Supplemental Indenture dated April 12, 2023 to Indenture dated February 2, 2021 among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
10.1*	Omnibus Amendment to Restricted Stock Unit Grant Agreements dated March 29, 2023.
22.1*	List of Subsidiary Guarantors.
31.1*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Number	Description
31.2*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
104*	The cover page from this Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, 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: May 4, 2023	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)

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