Targa Resources Corp. Reports Record Third Quarter 2025 Results and Announces Expectation for a 25% Increase to its 2026 Common Dividend

HOUSTON, Nov. 05, 2025 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported third quarter 2025 results. Third quarter 2025 net income attributable to Targa Resources Corp. was $478.4 million compared to $387.4 million for the third quarter of 2024. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”)(1) of $1,274.8 million for the third quarter of 2025 compared to $1,069.7 million for the third quarter of 2024. Highlights Record adjusted EBITDA for the third quarter of $1.3 billion, a 19% increase year over year and a 10% increase compared to the second quarterRecord Permian, NGL transportation, and fractionation volumes during the third quarterRepurchased approximately $156 million of common stock during the third quarter, and $605 million for the nine months ended September 30, 2025Estimate full year 2025 adjusted EBITDA to be around the top end of $4.65 billion to $4.85 billion rangeIn October, commenced operations at its new 275 million cubic feet per day (“MMcf/d”) Bull Moose II plant in the Permian DelawareIn September, announced plans to construct the Speedway NGL Pipeline, the Yeti plant in Permian Delaware, and Buffalo Run, an expansion of Targa’s intrastate natural gas pipeline system in the PermianAnnounced today plans to construct a new 275 MMcf/d gas plant in the Permian Delaware in New MexicoMoving forward with its 36-mile Forza interstate natural gas pipeline in the Permian DelawareExpect to recommend to Targa’s Board of Directors an annual common dividend per share of $5.00 in 2026, a 25% increase to 2025 On October 16, 2025, the Company declared a quarterly cash dividend of $1.00 per common share, or $4.00 per common share on an annualized basis, for the third quarter of 2025. Total cash dividends of approximately $215 million will be paid on November 17, 2025 on all outstanding shares of common stock to holders of record as of the close of business on October 31, 2025. During the third quarter of 2025, Targa repurchased 932,023 shares of its common stock at a weighted average per share price of $166.95 for a total net cost of $155.6 million. As of September 30, 2025, there was $1,410.6 million remaining under the Company’s Share Repurchase Programs. Third Quarter 2025 - Sequential Quarter over Quarter Commentary Targa reported record third quarter adjusted EBITDA of $1,274.8 million, representing a 10 percent increase compared to the second quarter of 2025. The sequential increase in adjusted EBITDA was attributable to higher volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems. In the G&P segment, higher sequential adjusted operating margin was attributable to record Permian natural gas inlet volumes and the in-service of its Pembrook II plant in Permian Midland during the third quarter. In the L&T segment, record NGL pipeline transportation and fractionation volumes and higher marketing margin drove the sequential increase in segment adjusted operating margin. Increased NGL pipeline transportation and fractionation volumes were predominantly attributable to higher supply volumes from Targa’s Permian G&P systems and the completion of a planned turnaround at a portion of Targa’s fractionation facilities in Mont Belvieu, Texas during the second quarter. Marketing margin increased due to greater optimization opportunities. Capitalization, Financing and Liquidity The Company’s total consolidated debt as of September 30, 2025 was $17,431.3 million, net of $112.5 million of debt issuance costs and $37.4 million of unamortized discount, with $15,329.2 million of outstanding senior unsecured notes, $1,295.0 million outstanding under the Commercial Paper Program, $600.0 million outstanding under the Securitization Facility, and $357.0 million of finance lease liabilities. Total consolidated liquidity as of September 30, 2025 was approximately $2.3 billion, including $2.2 billion available under the TRGP Revolver and $124.1 million of cash. Growth Projects Update In Targa’s G&P segment, the Company commenced operations of its new 275 MMcf/d Bull Moose II plant in the Permian Delaware in October 2025. Construction continues on Targa’s 275 MMcf/d East Pembrook and East Driver plants in Permian Midland, and its 275 MMcf/d Falcon II plant in Permian Delaware. In September 2025, Targa announced plans to construct a new 275 MMcf/d gas processing plant in the Permian Delaware (the “Yeti plant”). The Yeti plant is expected to begin operations in the third quarter of 2027. In November 2025, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced the construction of a new 275 MMcf/d natural gas processing plant (the “Copperhead plant”) in the Permian Delaware in New Mexico. The Copperhead plant is expected to begin operations in the first quarter of 2027. In Targa’s L&T segment, construction continues on the Company’s Delaware Express Pipeline expansion, its 150 MBbl/d Train 11 and Train 12 fractionators in Mont Belvieu, its GPMT LPG Export Expansion, and its Bull Run Extension. In September 2025, Targa announced plans to construct the Speedway NGL Pipeline (“Speedway”). Speedway will transport NGLs from Targa’s existing assets and future plant additions in the Permian Basin to Targa’s fractionation and storage complex in Mont Belvieu. Speedway is expected to begin operations in the third quarter of 2027. Targa also announced plans to construct Buffalo Run, a new 35-mile natural gas pipeline that will enhance connectivity across several Targa plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service. Buffalo Run is expected to be completed in stages and fully complete in early 2028. In November 2025, following the completion of its open season, Targa announced the Company is moving forward with a new 36-mile intra-basin natural gas pipeline in the Permian Delaware (“Forza”) to enhance connectivity to the Waha hub. Forza is expected to begin operations in mid-2028, pending receipt of necessary regulatory approvals. 2025 Outlook and Capital Allocation Update Targa now estimates full year adjusted EBITDA for 2025 to be around the top end of its $4.65 billion to $4.85 billion range. The Company’s estimate for 2025 net growth capital expenditures is approximately $3.3 billion, and its estimate for 2025 net maintenance capital expenditures remains unchanged at approximately $250 million. For the first quarter of 2026, Management intends to recommend to Targa’s Board of Directors an increase to its common dividend to $1.25 per common share or $5.00 per common share annualized. The recommended common dividend per share increase, if approved, would be effective for the first quarter of 2026 and payable in May 2026. Beyond 2026, Targa expects to be in position to continue to provide meaningful annual increases to its common dividend. For the nine months ended September 30, 2025, Targa has repurchased 3,538,285 shares of common stock at a weighted average per share price of $170.93 for a total net cost of $604.8 million. The Company expects to continue to be in position to opportunistically repurchase its common stock going forward with approximately $1.4 billion remaining under its common Share Repurchase Programs as of September 30, 2025. The Company is currently in its planning process, and consistent with previous years, Targa plans to detail its full year 2026 operational and financial outlook in February 2026 in conjunction with its fourth quarter 2025 earnings announcement. An earnings supplement presentation and updated investor presentation are available under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events. Conference Call The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on November 5, 2025 to discuss its third quarter results. The conference call can be accessed via webcast under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events, or by going directly to https://edge.media-server.com/mmc/p/ib9g4uey. A webcast replay will be available at the link above approximately two hours after the conclusion of the event. (1) Adjusted EBITDA and adjusted operating margin (segment) are non-GAAP financial measures and are discussed under “Non-GAAP Financial Measures.”Targa Resources Corp. – Consolidated Financial Results of Operations 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 “Non-GAAP Financial Measures.”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 “—Review of Segment Performance” for additional information on a segment basis. The increase in depreciation and amortization expense was primarily due to the impact of system expansions on the Company’s asset base. The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through the Company’s 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 acquisition of the remaining membership interest in Targa Badlands LLC in the first quarter of 2025 (the “Badlands Transaction”) 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 “—Review of Segment Performance” for additional information on a segment basis. The increase in depreciation and amortization expense was primarily due to the impact of system expansions on the Company’s asset base. The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through the Company’s 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 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”). 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. Review of Segment Performance The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and adjusted operating margin as important performance measures of the core profitability of its operations. These measures are key components of internal financial reporting and are reviewed for consistency and trend analysis. For a discussion of adjusted operating margin, see “Non-GAAP Financial Measures ― Adjusted Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Transportation. Gathering and Processing Segment The 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. The following table provides summary data regarding results of operations of this segment 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, 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 the Company’s 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 the Company owns a 72.8% undivided interest, and other plants that are owned 100% by the Company. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials.(5) Operations include facilities that are not wholly owned by the Company.(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 the Company’s 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 the Company’s 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) VolumeSettled PriceSpread (1) Gain(Loss) VolumeSettled PriceSpread (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 The 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 the Company’s other businesses. The Logistics and Transportation segment also includes Targa’s NGL pipeline system, which connects the Company’s gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company’s Downstream facilities in Mont Belvieu, Texas. The Company’s Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. The following table provides summary data regarding results of operations of this segment 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, 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 the Company’s 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 the Company’s 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. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s future commodity purchases and sales and natural gas transportation basis risk within the Company’s Logistics and Transportation segment. About Targa Resources Corp. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent infrastructure companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary domestic infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company’s assets connect natural gas and NGLs to domestic and international markets with growing demand for cleaner fuels and feedstocks. Targa is a FORTUNE 500 company and is included in the S&P 500. For more information, please visit the Company’s website at www.targaresources.com. Non-GAAP Financial Measures This press release includes the Company’s non-GAAP financial measures: adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment). The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Company utilizes non-GAAP measures to analyze the Company’s 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 the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within the Company’s industry, the Company’s definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of the Company’s non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes. Adjusted Operating Margin The Company defines adjusted operating margin for the Company’s segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by the Company’s 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; andrevenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and the Company’s 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; andNGL 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 the Company’s segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess: the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; andthe 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 the Company’s segments monthly as a core internal management process. The Company believes that investors benefit from having access to the same financial measures that management uses in evaluating the Company’s operating results. The reconciliation of the Company’s adjusted operating margin to the most directly comparable GAAP measure is presented under “Review of Segment Performance.” Adjusted EBITDA The Company defines adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that the Company believes should be adjusted consistent with the Company’s 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 the Company and by external users of the Company’s financial statements such as investors, commercial banks and others to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support the Company’s indebtedness and pay dividends to the Company’s investors. Adjusted Cash Flow from Operations and Adjusted Free Cash Flow The Company defines adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit . The Company defines 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 the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s 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. 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 the Company’s subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within Targa’s 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 the Company considers outside the ordinary course of the Company’s business and/or not reflective of the Company’s ongoing core operations. The Company may incur such charges from time to time, and the Company believes it is useful to exclude such charges because the Company does not consider them reflective of Company’s 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 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. The following table presents a reconciliation of estimated net income of the Company to estimated adjusted EBITDA for 2025: 2025E (In millions) Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to Estimated Adjusted EBITDA Net income attributable to Targa Resources Corp.$1,825.0 Interest expense, net 855.0 Income tax expense 540.0 Depreciation and amortization expense 1,525.0 Equity earnings (22.0)Distributions from unconsolidated affiliates 26.0 Compensation on equity grants 70.0 Risk management and other 24.0 Noncontrolling interests adjustments (1) 7.0 Estimated Adjusted EBITDA$4,850.0 (1) Represents adjustments related to the Company’s subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within Targa’s WestTX joint venture not subject to noncontrolling interest accounting. Regulation FD Disclosures The Company uses any of the following to comply with its disclosure obligations under Regulation FD: press releases, SEC filings, public conference calls, or the Company’s website. The Company routinely posts important information on its website at www.targaresources.com, including information that may be deemed to be material. The Company encourages investors and others interested in the company to monitor these distribution channels for material disclosures. Forward-Looking Statements Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements, including statements regarding the Company’s projected financial performance, capital spending and payment of future dividends. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, actions taken by other countries with significant hydrocarbon production, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of the Company’s completion of capital projects and business development efforts, the expected growth of volumes on the Company’s systems, the impact of significant public health crises, commodity price volatility due to ongoing or new global conflicts, the impact of disruptions in the bank and capital markets, changes in laws and regulations, particularly with regard to taxes, tariffs and international trade, and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its most recent Annual Report on Form 10-K, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Targa Investor RelationsInvestorRelations@targaresources.com(713) 584-1133

Targa Resources Corp. Reports Record Third Quarter 2025 Results and Announces Expectation for a 25% Increase to its 2026 Common Dividend

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