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.

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

Permian Delaware Processing Expansions

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

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

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

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

Fractionation Expansion

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

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

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

For the three and six months ended June 30, 2023, we repurchased 2,088,062 shares and 2,812,202 shares of our common stock at a weighted average per share price of $71.37 and $71.49 for a total net cost of $149.0 million and $201.0 million, respectively.

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

Program. There was $942.7 million remaining under the 2023 Share Repurchase Program as of June 30, 2023. We may discontinue the 2023 Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares thereunder.

Financing Activities

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

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

Corporation Tax Matters

As of June 30, 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. The 1% excise tax on stock buybacks is accrued in the current year for payment with the first quarterly excise tax return of the subsequent year.

On December 27, 2022, IRS Notice 2023-7 (the “Notice”) was issued by the U.S. Department of the Treasury and the IRS. The Notice provides guidance on the application of the CAMT which may be relied upon until final regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance, and a number of operational, economic, accounting and regulatory assumptions, including the safe harbor provided for in the Notice, the company 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).

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.

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.

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 June 30,								Six Months Ended June 30,
	2023				2022				2023				2022
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	329.3			$	596.4			$	826.3			$	684.4
Interest (income) expense, net		166.6				81.2				334.7				174.7
Income tax expense (benefit)		96.4				87.1				206.7				110.1
Depreciation and amortization expense		332.1				269.9				656.9				479.0
(Gain) loss on sale or disposition of assets		(1.7	)			(0.6	)			(3.2	)			(1.6	)
Write-down of assets		1.7				0.5				2.6				1.0
(Gain) loss from financing activities (1)		—				33.8				—				49.6
(Gain) loss from sale of equity method investment		—				(435.9	)			—				(435.9	)
Equity (earnings) loss		(3.4	)			(1.4	)			(3.2	)			(7.0	)
Distributions from unconsolidated affiliates and preferred partner interests, net		6.2				6.8				8.8				19.3
Compensation on equity grants		15.0				13.8				30.0				27.3
Risk management activities		(151.9	)			4.5				(327.7	)			182.7
Noncontrolling interests adjustments (2)		(1.2	)			10.3				(2.2	)			8.5
Adjusted EBITDA	$	789.1			$	666.4			$	1,729.7			$	1,292.1
Interest expense on debt obligations (3)		(163.6	)			(90.7	)			(328.8	)			(182.2	)
Maintenance capital expenditures, net (4)		(46.2	)			(39.7	)			(88.0	)			(77.4	)
Cash taxes		(3.5	)			(2.6	)			(7.7	)			(4.3	)
Distributable Cash Flow	$	575.8			$	533.4			$	1,305.2			$	1,028.2
Growth capital expenditures, net (4)		(579.5	)			(199.3	)			(994.9	)			(320.7	)
Adjusted Free Cash Flow	$	(3.7	)		$	334.1			$	310.3			$	707.5

(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 June 30,																Six Months Ended June 30,
	2023				2022				2023 vs. 2022								2023				2022				2023 vs. 2022
	(In millions)
Revenues:
Sales of commodities	$	2,914.6			$	5,624.2			$	(2,709.6	)			(48	%)		$	6,939.7			$	10,190.3			$	(3,250.6	)		(32	%)
Fees from midstream services		489.1				431.6				57.5				13	%			984.5				824.6				159.9			19	%
Total revenues		3,403.7				6,055.8				(2,652.1	)			(44	%)			7,924.2				11,014.9				(3,090.7	)		(28	%)
Product purchases and fuel		2,068.9				5,047.3				(2,978.4	)			(59	%)			5,088.0				9,251.5				(4,163.5	)		(45	%)
Operating expenses		272.6				215.8				56.8				26	%			530.7				399.3				131.4			33	%
Depreciation and amortization expense		332.1				269.9				62.2				23	%			656.9				479.0				177.9			37	%
General and administrative expense		81.0				71.0				10.0				14	%			163.4				138.0				25.4			18	%
Other operating (income) expense		—				(0.1	)			0.1				100	%			(0.6	)			(0.6	)			—			—
Income (loss) from operations		649.1				451.9				197.2				44	%			1,485.8				747.7				738.1			99	%
Interest expense, net		(166.6	)			(81.2	)			(85.4	)			105	%			(334.7	)			(174.7	)			(160.0	)		92	%
Equity earnings (loss)		3.4				1.4				2.0				143	%			3.2				7.0				(3.8	)		(54	%)
Gain (loss) from financing activities		—				(33.8	)			33.8				100	%			—				(49.6	)			49.6			100	%
Gain (loss) from sale of equity method investment		—				435.9				(435.9	)			(100	%)			—				435.9				(435.9	)		(100	%)
Other, net		(2.0	)			0.5				(2.5	)		NM					(4.9	)			—				(4.9	)		(100	%)
Income tax (expense) benefit		(96.4	)			(87.1	)			(9.3	)			11	%			(206.7	)			(110.1	)			(96.6	)		88	%
Net income (loss)		387.5				687.6				(300.1	)			(44	%)			942.7				856.2				86.5			10	%
Less: Net income (loss) attributable to noncontrolling interests		58.2				91.2				(33.0	)			(36	%)			116.4				171.8				(55.4	)		(32	%)
Net income (loss) attributable to Targa Resources Corp.		329.3				596.4				(267.1	)			(45	%)			826.3				684.4				141.9			21	%
Premium on repurchase of noncontrolling interests, net of tax		—				—				—				—				490.7				53.1				437.6		NM
Dividends on Series A Preferred Stock		—				8.2				(8.2	)			(100	%)			—				30.0				(30.0	)		(100	%)
Deemed dividends on Series A Preferred Stock		—				215.5				(215.5	)			(100	%)			—				215.5				(215.5	)		(100	%)
Net income (loss) attributable to common shareholders	$	329.3			$	372.7			$	(43.4	)			(12	%)		$	335.6			$	385.8			$	(50.2	)		(13	%)
Financial data:
Adjusted EBITDA (1)	$	789.1			$	666.4			$	122.7				18	%		$	1,729.7			$	1,292.1			$	437.6			34	%
Distributable cash flow (1)		575.8				533.4				42.4				8	%			1,305.2				1,028.2				277.0			27	%
Adjusted free cash flow (1)		(3.7	)			334.1				(337.8	)			(101	%)			310.3				707.5				(397.2	)		(56	%)

(1)

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

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

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

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($3,412.8 million), partially offset by higher natural gas, condensate and NGL volumes ($331.5 million) and the favorable impact of hedges ($371.7 million).

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

The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher natural gas, condensate and NGL 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, partially offset by the shortening of the depreciable lives of certain assets that were idled in 2022.

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

The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates on the Partnership’s accounts receivable securitization facility (the “Securitization Facility”), partially offset by higher capitalized interest resulting from higher growth capital investments.

During 2022, the Partnership redeemed its 5.875% Senior Notes due 2026 (the “5.875% Notes”) resulting in a net loss from financing activities.

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

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

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

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.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($5,197.2 million), partially offset by higher NGL, natural gas and condensate volumes ($1,028.9 million) and the favorable impact of hedges ($917.7 million).

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

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

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

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

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

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

During 2022, we completed the GCX Sale resulting in a gain from sale of an equity method investment.

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

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

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

The decrease in dividends on Series A Preferred 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:
June 30, 2023		$	502.5			$	408.0			$	151.9
June 30, 2022			474.7				322.3				(4.5	)
Six Months Ended:
June 30, 2023		$	1,040.9			$	937.1			$	327.7
June 30, 2022			872.3				674.5				(182.7	)

Gathering and Processing Segment

	Three Months Ended June 30,																			Six Months Ended June 30,
	2023					2022					2023 vs. 2022									2023					2022					2023 vs. 2022
		(In millions, except operating statistics and price amounts)
Operating margin	$		502.5			$		474.7			$		27.8				6	%		$		1,040.9			$		872.3			$		168.6				19	%
Operating expenses			189.8					141.4					48.4				34	%				371.2					258.0					113.2				44	%
Adjusted operating margin	$		692.3			$		616.1			$		76.2				12	%		$		1,412.1			$		1,130.3			$		281.8				25	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			2,504.3					2,132.0					372.3				17	%				2,426.9					2,103.7					323.2				15	%
Permian Delaware (5)			2,560.8					993.3					1,567.5				158	%				2,528.1					985.1					1,543.0				157	%
Total Permian			5,065.1					3,125.3					1,939.8				62	%				4,955.0					3,088.8					1,866.2				60	%
SouthTX (6)			371.0					271.2					99.8				37	%				363.5					216.9					146.6				68	%
North Texas			208.0					175.3					32.7				19	%				201.8					175.3					26.5				15	%
SouthOK (6)			395.0					460.4					(65.4	)			(14	%)				389.5					434.0					(44.5	)			(10	%)
WestOK			211.0					212.0					(1.0	)			—					207.6					207.2					0.4				—
Total Central			1,185.0					1,118.9					66.1				6	%				1,162.4					1,033.4					129.0				12	%
Badlands (6) (7)			128.9					129.4					(0.5	)			—					130.3					127.2					3.1				2	%
Total Field			6,379.0					4,373.6					2,005.4				46	%				6,247.7					4,249.4					1,998.3				47	%
Coastal			552.1					553.6					(1.5	)			—					530.7					577.7					(47.0	)			(8	%)
Total			6,931.1					4,927.2					2,003.9				41	%				6,778.4					4,827.1					1,951.3				40	%
NGL production, MBbl/d (3)
Permian Midland (4)			363.6					310.6					53.0				17	%				349.4					305.7					43.7				14	%
Permian Delaware (5)			367.9					135.8					232.1				171	%				355.4					132.8					222.6				168	%
Total Permian			731.5					446.4					285.1				64	%				704.8					438.5					266.3				61	%
SouthTX (6)			45.6					33.5					12.1				36	%				42.0					26.9					15.1				56	%
North Texas			24.3					19.6					4.7				24	%				23.7					19.4					4.3				22	%
SouthOK (6)			47.3					55.8					(8.5	)			(15	%)				43.1					53.1					(10.0	)			(19	%)
WestOK			12.5					16.6					(4.1	)			(25	%)				12.8					15.8					(3.0	)			(19	%)
Total Central			129.7					125.5					4.2				3	%				121.6					115.2					6.4				6	%
Badlands (6)			15.6					14.7					0.9				6	%				15.5					14.7					0.8				5	%
Total Field			876.8					586.6					290.2				49	%				841.9					568.4					273.5				48	%
Coastal			36.8					36.7					0.1				—					36.5					36.9					(0.4	)			(1	%)
Total			913.6					623.3					290.3				47	%				878.4					605.3					273.1				45	%
Crude oil, Badlands, MBbl/d			104.7					111.8					(7.1	)			(6	%)				107.7					117.2					(9.5	)			(8	%)
Crude oil, Permian, MBbl/d			29.4					28.8					0.6				2	%				27.5					29.7					(2.2	)			(7	%)
Natural gas sales, BBtu/d (3)			2,672.6					2,277.1					395.5				17	%				2,622.8					2,202.1					420.7				19	%
NGL sales, MBbl/d (3)			493.8					440.4					53.4				12	%				476.6					432.7					43.9				10	%
Condensate sales, MBbl/d			24.0					15.7					8.3				53	%				21.9					15.0					6.9				46	%
Average realized prices (8):
Natural gas, $/MMBtu			1.29					6.12					(4.83	)			(79	%)				1.94					5.15					(3.21	)			(62	%)
NGL, $/gal			0.41					0.89					(0.48	)			(54	%)				0.47					0.84					(0.37	)			(44	%)
Condensate, $/Bbl			69.52					103.10					(33.58	)			(33	%)				68.09					90.06					(21.97	)			(24	%)

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

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

		Three Months Ended June 30, 2023												Three Months Ended June 30, 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)			15.3			$	1.73			$	26.4				16.7			$	(3.29	)		$	(54.9	)
NGL (MMgal)			164.9				0.11				17.7				164.4				(0.47	)			(77.9	)
Crude oil (MBbl)			0.6				(3.67	)			(2.2	)			0.5				(51.00	)			(25.5	)
										$	41.9											$	(158.3	)

		Six Months Ended June 30, 2023												Six Months Ended June 30, 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)			35.0			$	1.51			$	52.9				34.2			$	(2.52	)		$	(86.1	)
NGL (MMgal)			349.0				0.08				27.2				334.8				(0.47	)			(155.8	)
Crude oil (MBbl)			1.2				(4.17	)			(5.0	)			1.0				(45.20	)			(45.2	)
										$	75.1											$	(287.1	)

(1)

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

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 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 I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, 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 and increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in the Delaware Basin. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI, Legacy II and Midway plants, and inflation impacts resulted in increased costs.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 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 I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, and continued strong producer activity. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity.

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

Logistics and Transportation Segment

	Three Months Ended June 30,																	Six Months Ended June 30,
	2023					2022					2023 vs. 2022							2023					2022					2023 vs. 2022
	(In millions, except operating statistics)
Operating margin	$		408.0			$		322.3			$		85.7			27%		$		937.1			$		674.5			$		262.6			39%
Operating expenses			82.5					74.4					8.1			11%				159.0					141.3					17.7			13%
Adjusted operating margin	$		490.5			$		396.7			$		93.8			24%		$		1,096.1			$		815.8			$		280.3			34%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)			620.7					492.3					128.4			26%				579.0					476.1					102.9			22%
Fractionation volumes			794.4					737.2					57.2			8%				776.7					720.1					56.6			8%
Export volumes (3)			303.2					342.6					(39.4	)		(12%)				338.1					341.7					(3.6	)		(1%)
NGL sales			947.0					906.9					40.1			4%				977.1					890.0					87.1			10%

(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 June 30, 2023 Compared to Three Months Ended June 30, 2022

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

The increase in operating expenses was primarily due to higher equipment rentals and higher compensation and benefits.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 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 from higher supply volumes primarily from our Permian Gathering and Processing systems and higher fees. LPG export margin increased primarily due to lower fuel and power costs.

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

Other

		Three Months Ended June 30,												Six Months Ended June 30,
		2023				2022				2023 vs. 2022				2023				2022				2023 vs. 2022
		(In millions)
Operating margin		$	151.9			$	(4.5	)		$	156.4			$	327.7			$	(182.7	)		$	510.4
Adjusted operating margin		$	151.9			$	(4.5	)		$	156.4			$	327.7			$	(182.7	)		$	510.4

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

Our Liquidity and Capital Resources

As of June 30, 2023, inclusive of our consolidated joint venture accounts, we had $169.4 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, 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 June 30, 2023, was:

		Consolidated Total
		(In millions)
Cash on hand (1)		$	169.4
Total availability under the Securitization Facility			547.9
Total availability under the TRGP Revolver and Commercial Paper Program			2,750.0
			3,467.3
Less: Outstanding borrowings under the Securitization Facility			(547.9	)
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program			(660.0	)
Outstanding letters of credit under the TRGP Revolver			(18.8	)
Total liquidity		$	2,240.6

(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 June 30, 2023, we had $18.8 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.

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 June 30, 2023 increased $118.3 million compared to December 31, 2022. The increase was primarily due to lower net borrowings on the Securitization Facility and lower net liabilities for hedging activities, partially offset by lower NGL Inventory and lower net receivables and product purchases and fuel payables resulting from lower commodity prices.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the 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 June 30, 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

Six Months Ended June 30,
2023				2022				2023 vs. 2022
(In millions)
$	1,846.6			$	1,383.7			$	462.9

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.

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

Cash Flows from Investing Activities

Six Months Ended June 30,
2023				2022				2023 vs. 2022
(In millions)
$	(1,074.6	)		$	248.4			$	(1,323.0	)

The change in net cash provided by (used in) investing activities was primarily due to higher outlays for property, plant and equipment in 2023 resulting from construction activities in the Permian region and Mont Belvieu, Texas, whereas in 2022 we received proceeds from the GCX Sale, partially offset by outlays for the acquisition of certain assets in South Texas.

Cash Flows from Financing Activities

	Six Months Ended June 30,
	2023				2022
	(In millions)
Source of Financing Activities, net
Debt, including financing costs	$	801.5			$	786.7
Redemption of Series A Preferred Stock		—				(965.2	)
Repurchase of noncontrolling interests		(1,091.9	)			(926.3	)
Dividends		(199.6	)			(217.8	)
Contributions from (distributions to) noncontrolling interests		(96.7	)			(167.7	)
Repurchase of shares		(234.9	)			(146.3	)
Net cash provided by (used in) financing activities	$	(821.6	)		$	(1,636.6	)

The decrease in net cash used in financing activities was primarily due to lower distributions to noncontrolling interests in 2023, whereas in 2022 we redeemed all of our Series A Preferred, partially offset by higher repurchases of noncontrolling interests and common stock in 2023 as compared to 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.

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

Summarized Combined Balance Sheet Information
		June 30, 2023				December 31, 2022
		(In millions)
ASSETS
Current assets		$	964.1			$	1,425.4
Current assets - affiliates			1.2				6.0
Long-term assets			14,749.3				14,398.8
Long-term assets - affiliates			10.5				10.5
Total assets		$	15,725.1			$	15,840.7
LIABILITIES AND OWNERS’ EQUITY
Current liabilities		$	1,684.9			$	2,169.6
Current liabilities - affiliates			22.3				28.0
Long-term liabilities			12,590.1				11,503.4
Targa Resources Corp. stockholders’ equity			1,427.8				2,139.7
Total liabilities and owners’ equity		$	15,725.1			$	15,840.7
Summarized Combined Statement of Operations Information
		Six Months Ended				Year Ended
		June 30, 2023				December 31, 2022
		(In millions)
Revenues		$	7,761.4			$	20,477.0
Operating income (loss)			1,249.5				1,108.3
Net income (loss)			714.2				909.0
Dividends on Series A Preferred			—				30.0

Common Stock Dividends

The following table details the dividends on common stock declared and/or paid by us for the six months ended June 30, 2023:

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

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 six months ended June 30, 2023 and 2022:

		Six Months Ended June 30,
		2023				2022
		(In millions)
Capital expenditures:
Growth (1)		$	994.7			$	326.3
Maintenance (2)			92.5				79.9
Gross capital expenditures			1,087.2				406.2
Change in capital project payables and accruals, net			(13.5	)			13.3
Cash outlays for capital projects		$	1,073.7			$	419.5

(1)

Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $994.9 million and $320.7 million for the six months ended June 30, 2023 and 2022.

(2)

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $88.0 million and $77.4 million for the six months ended June 30, 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.

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 June 30, 2023, there were $245.6 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate, and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.