Targa Resources Corp. press release

Targa Resources Corp. Reports Record Second Quarter 2026 Financial Results

2026-08-06

NYSE - New York Stock Exchange · Natural Gas · Natural Gas Liquids · Oil · United States · Corporate Finance

HOUSTON, Aug. 06, 2026 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported second quarter 2026 results.

Second quarter 2026 net income attributable to Targa Resources Corp. was $765 million compared to $629 million for the second quarter of 2025. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”)(1)of $1,603 million for the second quarter of 2026 compared to $1,163 million for the second quarter of 2025.

Highlights

Record adjusted EBITDA for the second quarter of $1.6 billion, an increase of 38% year-over-year and a 14% increase compared to the first quarter Record Permian inlet, NGL transportation, fractionation, and LPG export volumes during the second quarter Commenced operations of our Train 11 fractionator and Delaware Express NGL Pipeline expansion during the second quarter Commenced operations of our new East Driver processing plant in Permian Midland late in the second quarter, ahead of schedule Estimate full year 2026 adjusted EBITDA to be towards the top end of $5.7 billion to $5.9 billion range Continue to estimate 2026 net growth capital expenditures of approximately $4.5 billion

On July 16, 2026, the Company declared a quarterly cash dividend of $1.25 per common share, or $5.00 per common share on an annualized basis, for the second quarter of 2026. This dividend represents a 25 percent increase over the common dividend declared with respect to the second quarter of 2025. Total cash dividends of approximately $268 million will be paid on August 14, 2026 on all outstanding shares of common stock to holders of record as of the close of business on July 31, 2026.

During the second quarter of 2026, Targa repurchased 308,102 shares of its common stock at a weighted average per share price of $259.93 for a total net cost of $80 million. As of June 30, 2026, there was $1,239 million remaining under the Company’s share repurchase programs.

Second Quarter 2026 - Sequential Quarter over Quarter Commentary

Targa reported record second quarter adjusted EBITDA of $1,603 million, representing a 14 percent increase compared to the first quarter of 2026. The sequential increase was driven by higher marketing margin in our Logistics and Transportation (“L&T”) segment, record Permian volumes in our Gathering and Processing (“G&P”) segment, and record NGL transportation, fractionation, and LPG export volumes in our L&T segment.

In our G&P segment, higher sequential adjusted operating margin was driven by record Permian natural gas inlet volumes, partially offset by lower natural gas prices. Permian inlet volumes increased more than 450 million cubic feet per day (“MMcf/d”) despite temporary curtailments by certain producer customers in response to negative Waha natural gas prices in the second quarter.

In our L&T segment, higher sequential adjusted operating margin was driven by higher marketing margin, and record NGL pipeline transportation, fractionation, and LPG export volumes. Marketing margin increased due to greater optimization opportunities. NGL pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian G&P systems and the addition of Train 11 early in the second quarter of 2026. LPG export margin increased due to higher volumes and fees.

Capitalization, Financing and Liquidity

The Company’s total consolidated debt as of June 30, 2026 was $19,578 million, net of $128 million of debt issuance costs and $39 million of unamortized discount, with $17,900 million of outstanding senior unsecured notes, $600 million outstanding under our Commercial Paper Program, $451 million outstanding under our accounts receivable securitization facility (the “Securitization Facility”), and $794 million of finance lease liabilities.

Total consolidated liquidity as of June 30, 2026 was approximately $3.2 billion, including $2.9 billion available under the TRGP Revolver, $149 million under the Securitization Facility and $132 million of cash.

In July 2026, Targa amended the Securitization Facility to, among other things, extend the facility termination date to July 30, 2027 and increase borrowing capacity to up to $800 million.

Growth Projects Update

In our G&P segment, we commenced operations of our new East Driver plant in the Permian Midland late in the second quarter, ahead of schedule. Construction remains underway on our Copperhead, Yeti, Yeti II, Roadrunner III, and Copperhead II plants in Permian Delaware, and our G&P projects remain on track.

In our L&T segment, we commenced operations of our Train 11 fractionator in Mont Belvieu, TX and our Delaware Express NGL Pipeline expansion in the second quarter. Construction continues on our Train 12 and Train 13 fractionators in Mont Belvieu, our Speedway NGL Pipeline, our GPMT LPG Export Expansion, and our Bull Run, Buffalo Run and Forza intra-basin residue gas pipeline projects. Our L&T projects remain on track.

2026 Outlook

Given the strength of Targa’s performance through the first two quarters of the year, Targa now estimates full year 2026 adjusted EBITDA to be towards the top end of our $5.7 billion to $5.9 billion range. The higher outlook for full year 2026 is driven by the realization of strong marketing and optimization margin particularly in the first and second quarters of the year, and continued strength of volume growth of our integrated assets across the full year.

We continue to estimate net growth capital expenditures to be approximately $4.5 billion, and our estimate for 2026 net maintenance capital expenditures remains unchanged at approximately $250 million.

An earnings supplement presentation and updated investor presentation are available under Events and Presentations in the Investors section of our website at www.targaresources.com/investors/events.

Conference Call

We will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on August 6, 2026 to discuss second quarter results. The conference call can be accessed via webcast under Events and Presentations in the Investors section of our website at www.targaresources.com/investors/events, or by going directly to https://edge.media-server.com/mmc/p/o7q55fuf/lan/en/. 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 June 30, | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2026 | | 2025 | | 2026 vs. 2025 | | 2026 | | 2025 | | 2026 vs. 2025 | | | | | | | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | $ | 3,592.9 | | | $ | 3,636.3 | | | $ | (43.4 | ) | | (1 | %) | | $ | 6,937.5 | | | $ | 7,520.7 | | | $ | (583.2 | ) | (8 | %) | | | | Fees from midstream services | | 847.2 | | | | 623.8 | | | | 223.4 | | | 36 | % | | | 1,597.3 | | | | 1,300.9 | | | | 296.4 | | 23 | % | | | | Total revenues | | 4,440.1 | | | | 4,260.1 | | | | 180.0 | | | 4 | % | | | 8,534.8 | | | | 8,821.6 | | | | (286.8 | ) | (3 | %) | | | Product purchases and fuel | | 2,302.0 | | | | 2,436.0 | | | | (134.0 | ) | | (6 | %) | | | 4,696.5 | | | | 5,693.8 | | | | (997.3 | ) | (18 | %) | | | | Operating expenses | | 354.1 | | | | 323.6 | | | | 30.5 | | | 9 | % | | | 687.8 | | | | 627.2 | | | | 60.6 | | 10 | % | | | | Depreciation and amortization expense | | 453.1 | | | | 373.7 | | | | 79.4 | | | 21 | % | | | 879.1 | | | | 741.3 | | | | 137.8 | | 19 | % | | | | General and administrative expense | | 108.1 | | | | 95.0 | | | | 13.1 | | | 14 | % | | | 215.9 | | | | 189.5 | | | | 26.4 | | 14 | % | | | | Other operating (income) expense | | (11.7 | ) | | | (1.8 | ) | | | (9.9 | ) | | NM | | | | (25.9 | ) | | | (7.1 | ) | | | (18.8 | ) | 265 | % | | | | Income (loss) from operations | | 1,234.5 | | | | 1,033.6 | | | | 200.9 | | | 19 | % | | | 2,081.4 | | | | 1,576.9 | | | | 504.5 | | 32 | % | | | | Interest expense, net | | (236.6 | ) | | | (218.4 | ) | | | (18.2 | ) | | 8 | % | | | (464.2 | ) | | | (415.5 | ) | | | (48.7 | ) | 12 | % | | | | Equity earnings (loss) | | 7.8 | | | | 5.1 | | | | 2.7 | | | 53 | % | | | 16.4 | | | | 10.6 | | | | 5.8 | | 55 | % | | | | Other, net | | (0.8 | ) | | | 1.0 | | | | (1.8 | ) | | NM | | | | (17.4 | ) | | | 1.3 | | | | (18.7 | ) | NM | | | | | Income tax (expense) benefit | | (227.2 | ) | | | (184.1 | ) | | | (43.1 | ) | | 23 | % | | | (351.1 | ) | | | (256.3 | ) | | | (94.8 | ) | 37 | % | | | | Net income (loss) | | 777.7 | | | | 637.2 | | | | 140.5 | | | 22 | % | | | 1,265.1 | | | | 917.0 | | | | 348.1 | | 38 | % | | | | Less: Net income (loss) attributable to noncontrolling interests | | 13.1 | | | | 8.1 | | | | 5.0 | | | 62 | % | | | 20.9 | | | | 17.4 | | | | 3.5 | | 20 | % | | | | Net income (loss) attributable to Targa Resources Corp. | | 764.6 | | | | 629.1 | | | | 135.5 | | | 22 | % | | | 1,244.2 | | | | 899.6 | | | | 344.6 | | 38 | % | | | | Premium on repurchase of noncontrolling interests, net of tax | | — | | | | — | | | | — | | | — | | | | — | | | | 70.5 | | | | (70.5 | ) | (100 | %) | | | | Net income (loss) attributable to common shareholders | $ | 764.6 | | | $ | 629.1 | | | $ | 135.5 | | | 22 | % | | $ | 1,244.2 | | | $ | 829.1 | | | $ | 415.1 | | 50 | % | | | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | $ | 1,603.1 | | | $ | 1,163.0 | | | $ | 440.1 | | | 38 | % | | $ | 3,005.8 | | | $ | 2,341.5 | | | $ | 664.3 | | 28 | % | | | | Adjusted cash flow from operations (1) | | 1,371.0 | | | | 934.4 | | | | 436.6 | | | 47 | % | | | 2,550.9 | | | | 1,904.4 | | | | 646.5 | | 34 | % | | | | Adjusted free cash flow (1) | | 205.3 | | | | (9.6 | ) | | | 214.9 | | | NM | | | | 433.2 | | | | 318.6 | | | | 114.6 | | 36 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (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 June 30, 2026 Compared to Three Months Ended June 30, 2025

Commodity sales were relatively flat due to lower natural gas prices ($784.8 million) and the unfavorable impact of hedges ($291.6 million), partially offset by higher NGL and condensate prices ($597.8 million) and higher NGL, natural gas and condensate volumes ($435.2 million).

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

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

The increase in operating expenses was primarily due to higher labor and maintenance costs in part due to system expansions, and the acquisition of certain assets in the Permian Basin, partially offset by lower compressor rental costs.

See “—Review of Segment Performance—” for additional information on a segment basis.

The increase in depreciation and amortization expense was primarily due to the acquisition of certain assets in the Permian Basin, higher amortization of right-of-use assets for finance leases, and the impact of system expansions on the Company’s asset base.

The increase in general and administrative expense was primarily due to higher compensation and benefits.

The increase in other operating (income) expense was primarily due to lower asset abandonment costs.

The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

The decrease in commodity sales reflected lower natural gas and NGL prices ($1,309.2 million) and the unfavorable impact of hedges ($244.1 million), partially offset by higher NGL, natural gas and condensate volumes ($899.6 million) and higher condensate prices ($70.5 million).

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

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

The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes in part due to system expansions, partially offset by lower compressor rental costs.

See “—Review of Segment Performance—” for additional information on a segment basis.

The increase in depreciation and amortization expense was primarily due to the acquisition of certain assets in the Permian Basin, higher amortization of right-of-use assets for finance leases, and the impact of system expansions on the Company’s asset base.

The increase in general and administrative expense was primarily due to higher compensation and benefits.

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, and lower asset abandonment costs.

The increase in interest expense, net, was primarily due to higher borrowings, partially offset by an increase in capitalized interest.

The decrease in other, net, was primarily due to the premium paid on the redemption of all of the Partnership’s 6.875% Notes due 2029.

The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income.

The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in the first quarter of 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 June 30, | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | | | | | | | | | | | | | 2026 | | 2025 | | 2026 vs. 2025 | | 2026 | | 2025 | | 2026 vs. 2025 | | | | | | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | $ | 732.6 | | | $ | 587.6 | | $ | 145.0 | | | 25 | % | | $ | 1,436.1 | | | $ | 1,189.8 | | $ | 246.3 | | | 21 | % | | | | Operating expenses | | 240.9 | | | | 219.4 | | | 21.5 | | | 10 | % | | | 474.5 | | | | 427.6 | | | 46.9 | | | 11 | % | | | | Adjusted operating margin | $ | 973.5 | | | $ | 807.0 | | $ | 166.5 | | | 21 | % | | $ | 1,910.6 | | | $ | 1,617.4 | | $ | 293.2 | | | 18 | % | | | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 3,393.5 | | | | 3,106.2 | | | 287.3 | | | 9 | % | | | 3,274.4 | | | | 3,046.3 | | | 228.1 | | | 7 | % | | | | Permian Delaware | | 3,793.8 | | | | 3,171.8 | | | 622.0 | | | 20 | % | | | 3,685.6 | | | | 3,096.5 | | | 589.1 | | | 19 | % | | | | Total Permian | | 7,187.3 | | | | 6,278.0 | | | 909.3 | | | 14 | % | | | 6,960.0 | | | | 6,142.8 | | | 817.2 | | | 13 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | 1,010.3 | | | | 1,086.3 | | | (76.0 | ) | | (7 | %) | | | 1,018.8 | | | | 1,035.8 | | | (17.0 | ) | | (2 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | 133.8 | | | | 130.9 | | | 2.9 | | | 2 | % | | | 130.4 | | | | 133.9 | | | (3.5 | ) | | (3 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 577.5 | | | | 398.8 | | | 178.7 | | | 45 | % | | | 562.4 | | | | 398.8 | | | 163.6 | | | 41 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 8,908.9 | | | | 7,894.0 | | | 1,014.9 | | | 13 | % | | | 8,671.6 | | | | 7,711.3 | | | 960.3 | | | 12 | % | | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 506.1 | | | | 450.1 | | | 56.0 | | | 12 | % | | | 485.6 | | | | 439.9 | | | 45.7 | | | 10 | % | | | | Permian Delaware | | 500.8 | | | | 406.7 | | | 94.1 | | | 23 | % | | | 485.4 | | | | 386.8 | | | 98.6 | | | 25 | % | | | | Total Permian | | 1,006.9 | | | | 856.8 | | | 150.1 | | | 18 | % | | | 971.0 | | | | 826.7 | | | 144.3 | | | 17 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | 118.3 | | | | 120.2 | | | (1.9 | ) | | (2 | %) | | | 110.2 | | | | 109.1 | | | 1.1 | | | 1 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | 16.9 | | | | 16.6 | | | 0.3 | | | 2 | % | | | 16.5 | | | | 16.5 | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 38.7 | | | | 31.6 | | | 7.1 | | | 22 | % | | | 38.2 | | | | 32.2 | | | 6.0 | | | 19 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 1,180.8 | | | | 1,025.2 | | | 155.6 | | | 15 | % | | | 1,135.9 | | | | 984.5 | | | 151.4 | | | 15 | % | | | Crude oil gathered, MBbl/d | | 143.8 | | | | 116.5 | | | 27.3 | | | 23 | % | | | 139.5 | | | | 126.3 | | | 13.2 | | | 10 | % | | | | Natural gas sales, BBtu/d (3) | | 3,080.1 | | | | 2,819.5 | | | 260.6 | | | 9 | % | | | 3,060.3 | | | | 2,706.7 | | | 353.6 | | | 13 | % | | | | NGL sales, MBbl/d (3) | | 680.8 | | | | 606.4 | | | 74.4 | | | 12 | % | | | 653.5 | | | | 588.4 | | | 65.1 | | | 11 | % | | | | Condensate sales, MBbl/d | | 22.4 | | | | 20.1 | | | 2.3 | | | 11 | % | | | 22.1 | | | | 19.1 | | | 3.0 | | | 16 | % | | | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | (2.48 | ) | | | 1.01 | | | (3.49 | ) | | NM | | | | (0.97 | ) | | | 1.59 | | | (2.56 | ) | | (161 | %) | | | | NGL, $/gal | | 0.48 | | | | 0.41 | | | 0.07 | | | 17 | % | | | 0.44 | | | | 0.46 | | | (0.02 | ) | | (4 | %) | | | | Condensate, $/Bbl | | 90.57 | | | | 63.79 | | | 26.78 | | | 42 | % | | | 78.29 | | | | 67.80 | | | 10.49 | | | 15 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (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. Negative realized natural gas prices during the second quarter of 2026 were a result of an extended period of negative Waha prices due to significant egress constraint in the Permian Basin. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |