Targa Resources Corp.
For the period ended Jun 30, 2025. Filed Aug 7, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2025 · Filed Aug 7, 2025
TRGP$264.59-2.7%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-03-31; filed 2025-05-01.
0000950170-25-061595
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-06-30; filed 2025-08-07.
0001193125-25-175239
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 166 previous paragraphs and 188 current paragraphs.
130 unchanged; 30 reworded; 18 added; 6 removed; 0 previous and 10 current paragraphs rearranged.
Tables are not compared: 14 previous and 15 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (18)
Current report
Permian Basin Processing Expansions
Current report
In August 2025, we announced we are ordering long-lead items for our next potential gas plants across the Permian Basin.
Current report
Natural Gas Pipeline Extension
Current report
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.
Current report
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.
Current report
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.
Current report
The increase in commodity sales reflected higher NGL volumes ($304.2 million), higher natural gas prices ($296.4 million) and the favorable impact of hedges ($290.5 million), partially offset by lower NGL and condensate prices ($217.3 million).
Current report
The increase in product purchases and fuel reflected higher NGL volumes and natural gas prices, partially offset by lower NGL prices.
Current report
The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes, which were associated with system expansions and the planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
Current report
The increase in commodity sales reflected higher natural gas prices ($503.7 million), higher NGL volumes ($133.8 million) and the favorable impact of hedges ($34.4 million), partially offset by lower condensate prices ($41.6 million) and lower natural gas and condensate volumes ($29.3 million).
Current report
The increase in product purchases and fuel reflected higher natural gas prices and higher NGL volumes, partially offset by lower natural gas volumes.
Current report
The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes, which were associated with system expansions and the planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
Current report
The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.
Current report
Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Fractionation volumes were higher despite a planned turnaround at a portion of our facilities in Mont Belvieu, Texas. LPG export margin increased due to higher volumes and fees.
Current report
The increase in operating expenses was predominately due to a planned turnaround and system expansions.
Current report
Our working capital as of June 30, 2025 decreased $93.2 million compared to December 31, 2024. The decrease was primarily due to the reclassification of the 6.500% Notes due 2027 to Current debt obligations on our Consolidated Balance Sheets as a result of the issuance of a conditional notice of redemption in June 2025. This decrease was partially offset by a lower outstanding balance on the Securitization Facility, higher NGL inventory balance as well as lower payables and accrued liabilities, including payable balances related to capital spending on growth projects.
Current report
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.
Current report
In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.
Removed paragraphs (6)
Previous report
Permian Midland Processing Expansions
Previous report
Permian Delaware Processing Expansions
Previous report
Commodity sales are relatively flat reflecting lower NGL, natural gas and condensate volumes ($217.9 million), the unfavorable impact of hedges ($256.1 million) and lower condensate prices ($15.2 million), offset by higher natural gas and NGL prices ($431.2 million).
Previous report
Product purchases and fuel are relatively flat reflecting higher natural gas and NGL prices, offset by lower NGL and natural gas volumes.
Previous report
The increase in operating expenses is primarily due to higher labor, taxes and maintenance costs, partially offset by lower rental costs.
Previous report
Working capital as of March 31, 2025 decreased $245.6 million compared to December 31, 2024. The decrease was primarily due to a higher outstanding balance on the Securitization Facility, lower receivables resulting from lower NGL and natural gas volumes and higher net liabilities for hedging activities, partially offset by lower payables, including interest and accounts payable balances related to capital spending on growth projects.
Reworded paragraphs (30)
Previous wording
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.
Current wording
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.
Previous wording
In August 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose II plant”). The Bull Moose II plant is expected to begin operations in the first quarter of 2026.
Current wording
In August 2024, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose II plant”). The Bull Moose II plant is expected to begin operations in the fourth quarter of 2025.
Previous wording
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 third quarter of 2026.
Current wording
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.
Previous wording
In February 2025, we announced an intra-Delaware Basin expansion of our Grand Prix pipeline system in the Permian Delaware. The expansion is expected to begin operations in the third quarter of 2026.
Current wording
In February 2025, we announced an intra-Delaware Basin expansion of our Grand Prix pipeline system in the Permian Delaware. The expansion is expected to begin operations in the second quarter of 2026.
Previous wording
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 1.75 Bcf/d of natural gas through approximately 160 miles of 36-inch 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.
Current wording
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.
Previous wording
In May 2023, our Board of Directors approved a $1.0 billion common share repurchase program (the “2023 Share Repurchase Program”). In July 2024, our Board of Directors approved a new $1.0 billion common share repurchase program (the “2024 Share Repurchase Program and, together with the 2023 Share Repurchase Program, the “Share Repurchase Programs”). The amount authorized under the 2024 Share Repurchase Program was in addition to the amount remaining under the 2023 Share Repurchase Program. During the first quarter of 2025, we exhausted the 2023 Share Repurchase Program. We are not obligated to repurchase any specific dollar amount or number of shares under the 2024 Share Repurchase Program and may discontinue the program at any time.
Current wording
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.
Previous wording
For the three months ended March 31, 2025, we repurchased 651,163 shares of our common stock at a weighted average per share price of $191.86 for a total net cost of $124.9 million. As of March 31, 2025, there was $890.5 million remaining under the 2024 Share Repurchase Program.
Current wording
For the three and six months ended June 30, 2025, we repurchased 1,955,099 shares and 2,606,262 shares of our common stock at a weighted average per share price of $165.86 and $172.35 for a total net cost of $324.3 million and $449.2 million, respectively. As of June 30, 2025, there was $566.2 million remaining under the 2024 Share Repurchase Program. The amount authorized under the 2025 Share Repurchase Program is in addition to the amount that remained under the 2024 Share Repurchase Program.
Previous wording
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, and several operational, economic, accounting and regulatory assumptions, we are currently not an “applicable corporation”, but we are likely to become one in a subsequent year, potentially as early as 2026. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA and the CAMT and the possibility that the CAMT will be reduced or eliminated by the new Presidential administration, we will continue to monitor and evaluate the potential future impact to our financial statements.
Current wording
The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the One Big Beautiful Bill Act (the “OBBBA”), and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT at least through 2026. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA, the OBBBA, and the CAMT, we will continue to monitor and evaluate the potential future impact to our financial statements.
Previous wording
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.
Current wording
For a discussion of recent accounting pronouncements that will affect us, see Note 3 – Significant Accounting Policies to our Consolidated Financial Statements.
Previous wording
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.
Current wording
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.
Previous wording
Our profitability is impacted by our ability to add new sources of crude oil supply and natural gas 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.
Current wording
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.
Previous wording
Excludes amortization of interest expense. The three months ended March 31, 2024 includes $54.9 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”).
Current wording
Excludes amortization of interest expense. The three and six months ended June 30, 2024 includes $0.9 million and $55.8 million, respectively, of interest expense on a 2024 legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp (the “Splitter Agreement”).
Previous wording
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees.
Current wording
The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
Previous wording
The increase in depreciation and amortization expense is primarily due to the impact of system expansions on our asset base.
Current wording
The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.
Previous wording
The decrease in income tax expense is primarily due to a decrease in pre-tax book income.
Current wording
The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.
Previous wording
The decrease in net income attributable to noncontrolling interests is primarily due to the Badlands Transaction in 2025 and the acquisition of the remaining membership interest in Cedar Bayou Fractionators, L.P. in 2024 (the “CBF Acquisition”).
Current wording
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”).
Previous wording
The decrease in interest expense, net is due to recognition of cumulative interest on a legal ruling associated with the Splitter Agreement in 2024, partially offset by higher borrowings in 2025.
Current wording
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.
Previous wording
The premium on repurchase of noncontrolling interests, net of tax is due to the Badlands Transaction in 2025.
Current wording
The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in 2025.
Previous wording
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, and continued strong producer activity despite severe winter weather events which impacted volumes during the first quarter of 2025.
Current wording
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, and continued strong producer activity.
Previous wording
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing 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, the in-service of the Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin increased due to greater optimization opportunities.
Current wording
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, a full quarter of operation of Train 9 which was added during the second quarter of 2024, the in-service of Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Fractionation volumes were higher despite a planned turnaround at a portion of our facilities in Mont Belvieu, Texas. LPG export margin increased due to higher volumes and fees.
Previous wording
The increase in operating expenses was predominantly due to system expansions.
Current wording
The increase in operating expenses was predominately due to system expansions and a planned turnaround.
Previous wording
As of March 31, 2025, inclusive of our consolidated joint venture accounts, we had $151.4 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 $600.0 million accounts receivable securitization facility (the “Securitization Facility”), and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
Current wording
As of June 30, 2025, inclusive of our consolidated joint venture accounts, we had $113.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
Previous wording
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, higher operating expenses, higher interest payments, and higher outlays for hedging transactions.
Current wording
The increase in net cash provided by operating activities was primarily due to higher collections from customers resulting from increased revenues offset by higher payments related to product purchases and fuel as well as higher operating expenses and lower settlements for hedge transactions. In addition, during 2024, we made a nonrecurring one-time payment associated with the Splitter Agreement.
Previous wording
The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities in the Permian region and Mont Belvieu, Texas.
Current wording
The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities in the Permian region and Mont Belvieu, Texas, and contributions to unconsolidated affiliates.
Previous wording
The decrease in net cash used in financing activities was due to higher proceeds from debt financings in 2025 and lower distributions to noncontrolling interests subsequent to the CBF Acquisition in the fourth quarter of 2024 and the Badlands Transaction in the first quarter of 2025, partially offset by higher repurchases of noncontrolling interests due to the Badlands Transaction, higher dividends paid and higher repurchases of common stock in 2025. The increase in proceeds from debt financings was due to higher proceeds from our senior unsecured notes and borrowings under the Securitization Facility, partially offset by higher repayments of the Commercial Paper Program.
Current wording
The decrease in net cash used in financing activities was due to higher proceeds from debt financings in 2025, and lower distributions to noncontrolling interests subsequent to the CBF Acquisition in the fourth quarter of 2024 and the Badlands Transaction in the first quarter of 2025, partially offset by higher repurchases of noncontrolling interests due to the Badlands Transaction and higher dividends paid. The increase in cash flows from our debt activity was due to proceeds from the issuance of our senior unsecured notes in 2025, partially offset by higher repayments under the Commercial Paper Program and Securitization Facility. In addition, in 2024, we fully repaid the remaining balance outstanding under the $1.5 billion unsecured term loan facility.
Previous wording
The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2025:
Current wording
The following table details the dividends on common stock declared and/or paid by us for the six months ended June 30, 2025:
Previous wording
Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $594.5 million and $685.8 million for the three months ended March 31, 2025 and 2024.
Current wording
Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $1,479.6 million and $1,484.5 million for the six months ended June 30, 2025 and 2024.
Previous wording
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $47.3 million and $49.8 million for the three months ended March 31, 2025 and 2024.
Current wording
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $106.2 million and $102.7 million for the six months ended June 30, 2025 and 2024.
Previous wording
The decrease in growth capital expenditures is primarily due to timing of construction projects, including the Daytona NGL Pipeline, which was placed in-service in the third quarter of 2024.
Current wording
The decrease in growth capital expenditures was primarily due to timing of construction projects.
Previous wording
As of March 31, 2025, there were $53.7 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.
Current wording
As of June 30, 2025, there were $58.6 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
Rearranged current paragraphs (10)
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
The increase in interest expense, net, was primarily due to higher borrowings in 2025.
Current report — wording carried from elsewhere
The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
Current report — wording carried from elsewhere
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
Current report — wording carried from elsewhere
The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian, partially offset by lower volumes in other areas. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, and continued strong producer activity.
Current report — wording carried from elsewhere
The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.
Current report — wording carried from elsewhere
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, a full quarter of operation of Train 9 which was added during the second quarter of 2024, the in-service of