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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2024 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q for the quarter ended September 30, 2025 (“Quarterly Report”).

Overview

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

Our Operations

We are engaged primarily in the business of:

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

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

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

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

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

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

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

Recent Developments

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

Permian Basin Processing Expansions

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

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

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

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

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

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

In September 2025, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Yeti plant”). The Yeti plant is expected to begin operations in the third quarter of 2027.

In November 2025, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Copperhead plant”). The Copperhead plant is expected to begin operations in the first quarter of 2027.

Fractionation Expansions

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

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

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

NGL Pipeline Expansions

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

In September 2025, we announced plans to construct the Speedway NGL Pipeline (“Speedway”) which will transport NGLs from our existing assets and future plant additions in the Permian Basin to our fractionation and storage complex in Mont Belvieu, Texas. The project consists of approximately 500 miles of 30-inch diameter pipeline and associated infrastructure with an initial capacity of approximately 500 MBbl/d, expandable to 1,000 MBbl/d. Speedway is expected to begin operations in the third quarter of 2027.

LPG Export Expansion

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

Natural Gas Pipelines

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

In September 2025, we announced a new 35-mile intrastate natural gas pipeline that will enhance connectivity across several of our plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service (together, “Buffalo Run”) that will connect our Permian Midland and Permian Delaware intra-basin natural gas systems. Buffalo Run is expected to be completed in stages and fully complete in early 2028.

In November 2025, we announced the Forza Pipeline (“Forza”), a new 36-mile interstate natural gas pipeline in Permian Delaware that will connect our new and existing gas plants and enhance connectivity to the Waha hub. Forza will shortly file a certificate application with the Federal Energy Regulatory Commission and is expected to begin operations in the middle of 2028, pending receipt of necessary regulatory approvals.

Joint Ventures

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

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

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

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

Capital Allocation

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

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

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

For the three and nine months ended September 30, 2025, we repurchased 932,023 shares and 3,538,285 shares of our common stock at a weighted average per share price of $166.95 and $170.93 for a total net cost of $155.6 million and $604.8 million, respectively. As of September 30, 2025, there was $1,410.6 million remaining under the Share Repurchase Programs.

Financing Activities

In February 2025, we entered into a new $3.5 billion TRGP senior revolving credit facility (the “TRGP Revolver”), which provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion and matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times. In connection with our entry into the TRGP Revolver, we terminated our previous revolving credit facility (the “Previous TRGP Revolver”).

In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 (the “5.550% Notes due 2035”) and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055 (the “6.125% Notes due 2055”), resulting in net proceeds of approximately $2.0 billion. The 5.550% Notes due 2035 and 6.125% Notes due 2055 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. We used the net proceeds from the debt issuance to fund the Badlands Transaction and the remaining net proceeds for general corporate purposes, including to repay borrowings under our unsecured commercial paper note program (the “Commercial Paper Program”).

In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 (the “4.900% Notes due 2030”) and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036 (the “5.650% Notes due 2036”), resulting in net proceeds of approximately $1.5 billion. The 4.900% Notes due 2030 and 5.650% Notes due 2036 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. We used the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 (the “6.500% Notes due 2027”) in July 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

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

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

Corporation Tax Matters

As of September 30, 2025, Internal Revenue Service (the “IRS”) examinations are currently in process for the 2022 taxable year of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We do not expect there to be any audit adjustments that would materially change our taxable income. The IRS examinations for taxable years 2019 and 2020 of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes were closed on September 16, 2025 with no change.

Federal statutes of limitations for returns filed in 2021 (for calendar year 2020) have expired. The statute of limitations expired on substantially all 2020 state income tax returns that were filed prior to October 15, 2021. For Texas, the statute of limitations has expired for 2021 returns (for calendar year 2020). However, tax authorities could review and adjust carryover attributes (e.g., net operating losses) generated in a closed tax year if utilized in an open tax year.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the One Big Beautiful Bill Act (the “OBBBA”), and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.

Recent Accounting Pronouncements

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

How We Evaluate Our Operations

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

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

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

Throughput Volumes, Facility Efficiencies and Fuel Consumption

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

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

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

Operating Expenses

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

Capital Expenditures

Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of our 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 spend associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spend is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Non-GAAP Measures

We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures

as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

Adjusted Operating Margin

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

Gathering and Processing adjusted operating margin consists primarily of:

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

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

Logistics and Transportation adjusted operating margin consists primarily of:

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

system product gains and losses; and

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

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

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

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

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

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

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

Adjusted EBITDA

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

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow

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

Our Non-GAAP Financial Measures

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2025				2024				2025				2024
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	478.4			$	387.4			$	1,378.0			$	961.0
Interest (income) expense, net		221.3				184.9				636.8				589.5
Income tax expense (benefit)		134.3				97.0				390.6				274.1
Depreciation and amortization expense		383.5				355.4				1,124.8				1,044.5
(Gain) loss on sale or disposition of assets		(4.2	)			(1.0	)			(5.4	)			(2.7	)
Write-down of assets		1.5				2.7				13.1				4.0
(Gain) loss from financing activities		1.9				—				2.5				0.8
Equity (earnings) loss		(6.4	)			(2.2	)			(17.0	)			(7.9	)
Distributions from unconsolidated affiliates		7.6				4.4				18.7				16.6
Compensation on equity grants		17.5				17.7				52.2				47.4
Risk management activities		36.5				17.7				4.8				86.3
Noncontrolling interests adjustments (1)		2.9				1.6				8.6				2.6
Litigation expense (2)		—				4.1				8.6				4.1
Adjusted EBITDA	$	1,274.8			$	1,069.7			$	3,616.3			$	3,020.3
Interest expense on debt obligations (3)		(216.5	)			(181.2	)			(624.0	)			(578.5	)
Cash tax (expense) benefit		24.5				(3.9	)			(5.1	)			(10.1	)
Adjusted Cash Flow from Operations	$	1,082.8			$	884.6			$	2,987.2			$	2,431.7
Maintenance capital expenditures, net (4)		(57.0	)			(62.0	)			(163.2	)			(167.1	)
Growth capital expenditures, net (4)		(853.0	)			(698.4	)			(2,332.6	)			(2,180.4	)
Adjusted Free Cash Flow	$	172.8			$	124.2			$	491.4			$	84.2

(1)

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

(2)

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

(3)

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

(4)

Represents capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests, and includes contributions to investments in unconsolidated affiliates.

Consolidated Results of Operations

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

	Three Months Ended September 30,																Nine Months Ended September 30,
	2025				2024				2025 vs. 2024								2025				2024				2025 vs. 2024
	(In millions)
Revenues:
Sales of commodities	$	3,469.9			$	3,217.0			$	252.9				8	%		$	10,990.6			$	10,126.2			$	864.4			9	%
Fees from midstream services		681.3				634.8				46.5				7	%			1,982.2				1,850.0				132.2			7	%
Total revenues		4,151.2				3,851.8				299.4				8	%			12,972.8				11,976.2				996.6			8	%
Product purchases and fuel		2,506.4				2,365.0				141.4				6	%			8,200.2				7,780.4				419.8			5	%
Operating expenses		333.5				301.0				32.5				11	%			960.7				869.7				91.0			10	%
Depreciation and amortization expense		383.5				355.4				28.1				8	%			1,124.8				1,044.5				80.3			8	%
General and administrative expense		104.8				102.6				2.2				2	%			294.3				287.4				6.9			2	%
Other operating (income) expense		(13.9	)			(0.4	)			(13.5	)		NM					(21.0	)			(0.7	)			(20.3	)	NM
Income (loss) from operations		836.9				728.2				108.7				15	%			2,413.8				1,994.9				418.9			21	%
Interest expense, net		(221.3	)			(184.9	)			(36.4	)			20	%			(636.8	)			(589.5	)			(47.3	)		8	%
Equity earnings (loss)		6.4				2.2				4.2				191	%			17.0				7.9				9.1			115	%
Other, net		(1.1	)			(0.4	)			(0.7	)		NM					0.2				0.3				(0.1	)	NM
Income tax (expense) benefit		(134.3	)			(97.0	)			(37.3	)			38	%			(390.6	)			(274.1	)			(116.5	)		43	%
Net income (loss)		486.6				448.1				38.5				9	%			1,403.6				1,139.5				264.1			23	%
Less: Net income (loss) attributable to noncontrolling interests		8.2				60.7				(52.5	)			(86	%)			25.6				178.5				(152.9	)		(86	%)
Net income (loss) attributable to Targa Resources Corp.		478.4				387.4				91.0				23	%			1,378.0				961.0				417.0			43	%
Premium on repurchase of noncontrolling interests, net of tax		—				—				—				—				70.5				—				70.5			100	%
Net income (loss) attributable to common shareholders	$	478.4			$	387.4			$	91.0				23	%		$	1,307.5			$	961.0			$	346.5			36	%
Financial data:
Adjusted EBITDA (1)	$	1,274.8			$	1,069.7			$	205.1				19	%		$	3,616.3			$	3,020.3			$	596.0			20	%
Adjusted cash flow from operations (1)		1,082.8				884.6				198.2				22	%			2,987.2				2,431.7				555.5			23	%
Adjusted free cash flow (1)		172.8				124.2				48.6				39	%			491.4				84.2				407.2			484	%

(1)

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

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

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

The increase in commodity sales reflected higher natural gas prices ($322.3 million) and higher NGL volumes ($213.8 million), partially offset by lower NGL prices ($263.3 million) and the unfavorable impact of hedges ($16.6 million).

The increase in fees from midstream services was primarily due to higher gas gathering and processing fees and higher transportation and fractionation fees.

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

The increase in operating expenses was primarily due to higher maintenance, taxes and labor costs as a result of system expansions.

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

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

The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through our carbon capture and sequestration activities.

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

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

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

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

The increase in commodity sales reflected higher natural gas prices ($815.5 million), higher NGL volumes ($354.1 million) and the favorable impact of hedges ($17.8 million), partially offset by lower NGL and condensate prices ($318.1 million).

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

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

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

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

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

The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through our carbon capture and sequestration activities.

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

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

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

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

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

		Gathering and Processing				Logistics and Transportation				Other
		(In millions)
Three Months Ended:
September 30, 2025		$	637.6			$	710.2			$	(36.5	)
September 30, 2024			584.3				619.2				(17.7	)
Nine Months Ended:
September 30, 2025		$	1,827.4			$	1,989.3			$	(4.8	)
September 30, 2024			1,713.4				1,699.0				(86.3	)

Gathering and Processing Segment

	Three Months Ended September 30,																			Nine Months Ended September 30,
	2025					2024					2025 vs. 2024									2025					2024					2025 vs. 2024
		(In millions, except operating statistics and price amounts)
Operating margin	$		637.6			$		584.3			$		53.3				9	%		$		1,827.4			$		1,713.4			$		114.0				7	%
Operating expenses			236.1					203.7					32.4				16	%				663.7					597.2					66.5				11	%
Adjusted operating margin	$		873.7			$		788.0			$		85.7				11	%		$		2,491.1			$		2,310.6			$		180.5				8	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			3,246.0					3,044.2					201.8				7	%				3,113.5					2,886.1					227.4				8	%
Permian Delaware			3,375.6					2,900.2					475.4				16	%				3,190.6					2,785.2					405.4				15	%
Total Permian			6,621.6					5,944.4					677.2				11	%				6,304.1					5,671.3					632.8				11	%
Central (5)			1,071.0					1,078.1					(7.1	)			(1	%)				1,047.6					1,080.9					(33.3	)			(3	%)
Badlands (5) (6)			129.9					145.4					(15.5	)			(11	%)				132.5					138.8					(6.3	)			(5	%)
Coastal			445.9					402.1					43.8				11	%				414.6					464.3					(49.7	)			(11	%)
Total			8,268.4					7,570.0					698.4				9	%				7,898.8					7,355.3					543.5				7	%
NGL production, MBbl/d (3)
Permian Midland (4)			478.3					450.6					27.7				6	%				452.8					422.6					30.2				7	%
Permian Delaware			452.2					377.4					74.8				20	%				408.8					349.7					59.1				17	%
Total Permian			930.5					828.0					102.5				12	%				861.6					772.3					89.3				12	%
Central (5)			111.1					98.0					13.1				13	%				109.7					104.4					5.3				5	%
Badlands (5)			16.6					18.3					(1.7	)			(9	%)				16.5					17.0					(0.5	)			(3	%)
Coastal			36.9					33.9					3.0				9	%				33.8					35.8					(2.0	)			(6	%)
Total			1,095.1					978.2					116.9				12	%				1,021.6					929.5					92.1				10	%
Crude oil, Badlands, MBbl/d			84.6					122.4					(37.8	)			(31	%)				93.9					105.4					(11.5	)			(11	%)
Crude oil, Permian, MBbl/d			25.2					26.7					(1.5	)			(6	%)				26.8					27.4					(0.6	)			(2	%)
Natural gas sales, BBtu/d (3)			2,930.8					2,842.9					87.9				3	%				2,782.3					2,779.2					3.1				—
NGL sales, MBbl/d (3)			634.8					581.5					53.3				9	%				604.1					550.1					54.0				10	%
Condensate sales, MBbl/d			18.0					17.3					0.7				4	%				18.7					19.2					(0.5	)			(3	%)
Average realized prices (7):
Natural gas, $/MMBtu			1.20					0.09					1.11			NM						1.45					0.54					0.91				169	%
NGL, $/gal			0.39					0.44					(0.05	)			(11	%)				0.43					0.45					(0.02	)			(4	%)
Condensate, $/Bbl			67.75					77.20					(9.45	)			(12	%)				67.78					75.60					(7.82	)			(10	%)

(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.

(3)

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

(4)

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

(5)

Operations include facilities that are not wholly owned by us.

(6)

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

(7)

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

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 September 30, 2025												Three Months Ended September 30, 2024
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			7.5			$	1.61			$	12.1				9.4			$	2.53			$	23.8
NGL (MMgal)			69.3				0.04				2.6				102.8				0.08				8.2
Crude oil (MBbl)			0.7				6.29				4.4				0.6				(0.67	)			(0.4	)
										$	19.1											$	31.6

		Nine Months Ended September 30, 2025												Nine Months Ended September 30, 2024
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			22.6			$	1.55			$	35.0				35.6			$	1.94			$	69.2
NGL (MMgal)			250.5				(0.02	)			(4.4	)			348.9				0.04				14.9
Crude oil (MBbl)			2.1				5.00				10.5				1.4				(5.57	)			(7.8	)
										$	41.1											$	76.3

(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 September 30, 2025 Compared to Three Months Ended September 30, 2024

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

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

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

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

Logistics and Transportation Segment

	Three Months Ended September 30,																	Nine Months Ended September 30,
	2025					2024					2025 vs. 2024							2025					2024					2025 vs. 2024
	(In millions, except operating statistics)
Operating margin	$		710.2			$		619.2			$		91.0			15%		$		1,989.3			$		1,699.0			$		290.3			17%
Operating expenses			98.6					98.1					0.5			1%				299.5					273.5					26.0			10%
Adjusted operating margin	$		808.8			$		717.3			$		91.5			13%		$		2,288.8			$		1,972.5			$		316.3			16%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes			1,017.0					829.2					187.8			23%				941.2					777.0					164.2			21%
Fractionation volumes			1,134.3					953.8					180.5			19%				1,028.3					884.7					143.6			16%
Export volumes			407.4					403.9					3.5			1%				425.9					412.3					13.6			3%
NGL sales			1,249.3					1,162.0					87.3			8%				1,195.8					1,136.1					59.7			5%

(1)

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

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

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, partially offset by lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, a full quarter of operation of Daytona NGL Pipeline which commenced operations during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin decreased due to fewer optimization opportunities.

Operating expenses were relatively flat despite system expansions which were offset by lower repairs and maintenance.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

which commenced operations during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. LPG export margin increased due to higher volumes and fees.

The increase in operating expenses was predominantly due to system expansions and the planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

Other

		Three Months Ended September 30,												Nine Months Ended September 30,
		2025				2024				2025 vs. 2024				2025				2024				2025 vs. 2024
		(In millions)
Operating margin		$	(36.5	)		$	(17.7	)		$	(18.8	)		$	(4.8	)		$	(86.3	)		$	81.5
Adjusted operating margin		$	(36.5	)		$	(17.7	)		$	(18.8	)		$	(4.8	)		$	(86.3	)		$	81.5

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 September 30, 2025, inclusive of our consolidated joint venture accounts, we had $124.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

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

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of September 30, 2025, was:

		Consolidated Total
		(In millions)
Cash on hand (1)		$	124.1
Total availability under the Securitization Facility			600.0
Total availability under the TRGP Revolver and Commercial Paper Program			3,500.0
			4,224.1
Outstanding borrowings under the Securitization Facility			(600.0	)
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program			(1,295.0	)
Outstanding letters of credit under the TRGP Revolver			(26.7	)
Total liquidity		$	2,302.4

(1)

Includes cash held in our consolidated joint venture accounts.

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

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

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of September 30, 2025, we had $26.7 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain

counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

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

Our working capital as of September 30, 2025 increased $208.7 million compared to December 31, 2024. The increase was primarily due to lower product purchases and fuel payables resulting from lower NGL and natural gas prices, a higher NGL inventory balance as well as lower interest payable and accrued liabilities, partially offset by a higher outstanding balance on the Securitization Facility and lower receivables resulting from lower NGL and natural gas prices.

Long-term Financing

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

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

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

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

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

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

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

Compliance with Debt Covenants

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

Cash Flow Analysis

Cash Flows from Operating Activities

Nine Months Ended September 30,
2025				2024				2025 vs. 2024
(In millions)
$	2,411.9			$	2,321.8			$	90.1

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

The increase in net cash provided by operating activities was primarily due to higher collections from customers resulting from increased revenues in 2025 compared to 2024, partially offset by an increase in payments for product purchases and fuel, operating costs and interest on debt. In addition, during 2024, we made a nonrecurring one-time payment associated with the Splitter Agreement.

Cash Flows from Investing Activities

Nine Months Ended September 30,
2025				2024				2025 vs. 2024
(In millions)
$	(2,461.2	)		$	(2,275.0	)		$	(186.2	)

The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities and an increase in contributions to unconsolidated affiliates.

Cash Flows from Financing Activities

	Nine Months Ended September 30,
	2025				2024
	(In millions)
Source of Financing Activities, net
Debt, including financing costs	$	3,122.9			$	1,254.3
Repurchase of noncontrolling interests		(1,800.4	)			(1.3	)
Dividends paid to common shareholders		(602.5	)			(450.6	)
Contributions from (distributions to) noncontrolling interests, net		(28.9	)			(163.7	)
Repurchases of shares		(675.0	)			(700.0	)
Net cash provided by (used in) financing activities	$	16.1			$	(61.3	)

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

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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

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

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

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

Summarized Combined Balance Sheet Information
		September 30, 2025				December 31, 2024
		(In millions)
ASSETS
Current assets		$	131.7			$	127.8
Current assets - affiliates			3.4				22.7
Long-term assets			82.5				76.4
Total assets		$	217.6			$	226.9
LIABILITIES AND OWNERS’ EQUITY (DEFICIT)
Current liabilities		$	143.0			$	262.0
Long-term liabilities			4,424.8				5,121.7
Targa Resources Corp. stockholders’ equity (deficit)			(4,350.2	)			(5,156.8	)
Total liabilities and owners’ equity (deficit)		$	217.6			$	226.9
Summarized Combined Statement of Operations Information
		Nine Months Ended September 30, 2025				Year Ended December 31, 2024
		(In millions)
Operating income (loss)		$	(258.4	)		$	(328.0	)
Net income (loss)			(450.0	)			(583.0	)

Common Stock Dividends

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

Three Months Ended		Date Paid or To Be Paid		Total Common Dividends Declared				Amount of Common Dividends Paid or To Be Paid				Dividends on Share-Based Awards				Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
September 30, 2025		November 17, 2025		$	216.4			$	214.6			$	1.8			$	1.00000
June 30, 2025		August 15, 2025			217.6				215.2				2.4				1.00000
March 31, 2025		May 15, 2025			219.0				216.9				2.1				1.00000
December 31, 2024		February 14, 2025			165.2				163.6				1.6				0.75000

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

Capital Expenditures

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

		Nine Months Ended September 30,
		2025				2024
		(In millions)
Capital expenditures:
Growth (1)		$	2,208.3			$	2,150.3
Maintenance (2)			164.1				173.6
Gross capital expenditures			2,372.4				2,323.9
Change in capital project payables and accruals, net			(2.3	)			(85.0	)
Cash outlays for capital projects		$	2,370.1			$	2,238.9

(1)

Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $2,332.6 million and $2,180.4 million for the nine months ended September 30, 2025 and 2024.

(2)

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $163.2 million and $167.1 million for the nine months ended September 30, 2025 and 2024.

The increase in growth capital expenditures was primarily due to construction activities during 2025.

Off-Balance Sheet Arrangements

As of September 30, 2025, there were $58.5 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.