Targa Resources Corp. press release

Targa Resources Corp. Reports Third Quarter 2026 Financial Results and Announces Expectation for a 20% Increase to its 2027 Common Dividend

2026-11-05

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

HOUSTON, Nov. 05, 2026 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported third quarter 2026 results.

Third quarter 2026 net income attributable to Targa Resources Corp. was $658 million compared to $478 million for the third quarter of 2025. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”)(1)of $1,504 million for the third quarter of 2026 compared to $1,275 million for the third quarter of 2025.

Highlights

Adjusted EBITDA for the third quarter of $1.5 billion, an increase of 18% year-over-year Record Permian inlet, NGL transportation and fractionation volumes during the third quarter In August 2026, announced new 20-year, fee-based integrated midstream agreements with subsidiaries of ExxonMobil for natural gas gathering and processing, and downstream services in the Permian Basin In August 2026, announced three new natural gas processing plants in the Permian Delaware (“Wrangler,” “Ranger” and “Ranger II”) to support the new commercial agreements with ExxonMobil Recently commenced operations of our Train 12 fractionator and our Bull Run Extension intra-basin residue pipeline, with our Copperhead plant in the Permian Delaware currently in start-up, all ahead of schedule Announced today we are ordering long-lead items for an additional processing plant in the Permian Midland and two additional processing plants in the Permian Delaware Announced today we are moving forward with a new NGL fractionation train in Mont Belvieu, TX (“Train 14”) Now expect full year 2026 adjusted EBITDA to be at least $6.0 billion Continue to estimate 2026 net growth capital expenditures of approximately $5.0 billion Expect to recommend to Targa’s Board of Directors an annual common dividend per share of $6.00 in 2027, a 20% increase to 2026

On October 13, 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 third quarter of 2026. This dividend represents a 25 percent increase over the common dividend declared with respect to the third quarter of 2025. Total cash dividends of approximately $268 million will be paid on November 17, 2026 on all outstanding shares of common stock to holders of record as of the close of business on October 30, 2026.

During the third quarter of 2026, Targa repurchased 180,768 shares of our common stock at a weighted average per share price of $287.64 for a total net cost of $52 million. As of September 30, 2026, there was $1,187 million remaining under the Company’s share repurchase programs.

Third Quarter 2026 - Sequential Quarter over Quarter Commentary

Targa reported third quarter adjusted EBITDA of $1,504 million, representing a 6 percent decrease compared to the second quarter of 2026. Record Permian inlet volumes in our Gathering and Processing (“G&P”) segment and record NGL transportation and fractionation volumes in our Logistics and Transportation (“L&T”) segment were offset by lower marketing margin and lower LPG export margin in our L&T segment.

In our G&P segment, higher sequential adjusted operating margin was driven by record natural gas inlet volumes in the Permian region and higher natural gas and NGL prices.

In our L&T segment, record NGL pipeline transportation and fractionation margin was offset by lower marketing margin and lower LPG export margin. NGL pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian G&P systems. Marketing margin was lower due to fewer optimization opportunities. LPG export margin was lower due to lower volumes and fees.

Capitalization, Financing and Liquidity

The Company’s total consolidated debt as of September 30, 2026 was $19.8 billion, net of $124 million of debt issuance costs and $38 million of unamortized discount, with $17.9 billion of outstanding senior unsecured notes, $860 million outstanding under our Commercial Paper Program, $451 million outstanding under our accounts receivable securitization facility (the “Securitization Facility”), and $796 million of finance lease liabilities.

Total consolidated liquidity as of September 30, 2026 was approximately $2.9 billion, including $2.6 billion available under the TRGP Revolver, $149 million under the Securitization Facility and $143 million of cash.

Growth Projects Update

In our G&P segment, Targa’s Copperhead plant in the Permian Delaware is currently in start-up, ahead of schedule. The Company now expects our Yeti and Yeti II plants to begin operations in the second quarter of 2027 and third quarter of 2027, earlier than previously expected. Construction continues on our Roadrunner III, Copperhead II, Wrangler, Ranger, and Ranger II plants in the Permian Delaware, and these projects remain on track.

In response to increasing production, the infrastructure needs of our customers and recent commercial success, we are ordering long-lead items for our next processing plant in the Permian Midland and our next two processing plants in the Permian Delaware. We are evaluating the timing and expect these new plants will likely be needed in 2028 or early 2029.

In our L&T segment, Targa recently commenced operations of our Train 12 fractionator in Mont Belvieu, TX and our Bull Run Extension intra-basin residue gas pipeline project in the fourth quarter of 2026, ahead of schedule. Construction continues on our Train 13 fractionator, Speedway NGL Pipeline, GPMT LPG Export Expansion, and Buffalo Run, Bull Run II, and Forza intra-basin residue gas pipeline projects, which remain on track.

In November 2026, in response to increasing production and to meet the infrastructure needs of our customers, we announced a new 150 thousand barrels per day (“MBbl/d”) NGL fractionator, Train 14, in Mont Belvieu, TX. Train 14 is expected to begin operations in the first quarter of 2029.

2026 Outlook and Capital Allocation Update

Given the strength of Targa’s operating performance through the first three quarters of the year, Targa now estimates full year 2026 adjusted EBITDA to be at least $6.0 billion. We continue to estimate net growth capital expenditures to be approximately $5.0 billion, and our estimate for 2026 net maintenance capital expenditures remains unchanged at approximately $250 million.

For the first quarter of 2027, management intends to recommend to Targa’s Board of Directors an increase to its common dividend to $1.50 per common share or $6.00 per common share annualized. The recommended common dividend per share increase, if approved, would be effective for the first quarter of 2027 and payable in May 2027. Beyond 2027, we expect to be in position to continue to provide meaningful annual increases to our common dividend.

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 November 5, 2026 to discuss third 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/5srx7xm2/. 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, | | | | | | | | | | | | | | | | | | | | | | | 2026 | | | 2025 | | | 2026 vs. 2025 | | | 2026 | | | 2025 | | | 2026 vs. 2025 | | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | $ | 4,722.9 | | | $ | 3,469.9 | | | $ | 1,253.0 | | | | 36 | % | | $ | 11,660.4 | | | $ | 10,990.6 | | | $ | 669.8 | | | 6 | % | | Fees from midstream services | | 875.7 | | | | 681.3 | | | | 194.4 | | | | 29 | % | | | 2,473.0 | | | | 1,982.2 | | | | 490.8 | | | 25 | % | | Total revenues | | 5,598.6 | | | | 4,151.2 | | | | 1,447.4 | | | | 35 | % | | | 14,133.4 | | | | 12,972.8 | | | | 1,160.6 | | | 9 | % | | Product purchases and fuel | | 3,578.6 | | | | 2,506.4 | | | | 1,072.2 | | | | 43 | % | | | 8,275.1 | | | | 8,200.2 | | | | 74.9 | | | 1 | % | | Operating expenses | | 372.3 | | | | 333.5 | | | | 38.8 | | | | 12 | % | | | 1,060.1 | | | | 960.7 | | | | 99.4 | | | 10 | % | | Depreciation and amortization expense | | 459.6 | | | | 383.5 | | | | 76.1 | | | | 20 | % | | | 1,338.7 | | | | 1,124.8 | | | | 213.9 | | | 19 | % | | General and administrative expense | | 112.9 | | | | 104.8 | | | | 8.1 | | | | 8 | % | | | 328.8 | | | | 294.3 | | | | 34.5 | | | 12 | % | | Other operating (income) expense | | (20.8 | ) | | | (13.9 | ) | | | (6.9 | ) | | | 50 | % | | | (46.7 | ) | | | (21.0 | ) | | | (25.7 | ) | | 122 | % | | Income (loss) from operations | | 1,096.0 | | | | 836.9 | | | | 259.1 | | | | 31 | % | | | 3,177.4 | | | | 2,413.8 | | | | 763.6 | | | 32 | % | | Interest expense, net | | (232.8 | ) | | | (221.3 | ) | | | (11.5 | ) | | | 5 | % | | | (697.0 | ) | | | (636.8 | ) | | | (60.2 | ) | | 9 | % | | Equity earnings (loss) | | 10.2 | | | | 6.4 | | | | 3.8 | | | | 59 | % | | | 26.6 | | | | 17.0 | | | | 9.6 | | | 56 | % | | Other, net | | (22.6 | ) | | | (1.1 | ) | | | (21.5 | ) | | NM | | | | (40.0 | ) | | | 0.2 | | | | (40.2 | ) | NM | | | | | Income tax (expense) benefit | | (174.7 | ) | | | (134.3 | ) | | | (40.4 | ) | | | 30 | % | | | (525.8 | ) | | | (390.6 | ) | | | (135.2 | ) | | 35 | % | | Net income (loss) | | 676.1 | | | | 486.6 | | | | 189.5 | | | | 39 | % | | | 1,941.2 | | | | 1,403.6 | | | | 537.6 | | | 38 | % | | Less: Net income (loss) attributable to noncontrolling interests | | 17.9 | | | | 8.2 | | | | 9.7 | | | | 118 | % | | | 38.8 | | | | 25.6 | | | | 13.2 | | | 52 | % | | Net income (loss) attributable to Targa Resources Corp. | | 658.2 | | | | 478.4 | | | | 179.8 | | | | 38 | % | | | 1,902.4 | | | | 1,378.0 | | | | 524.4 | | | 38 | % | | Premium on repurchase of noncontrolling interests, net of tax | | — | | | | — | | | | — | | | | — | | | | — | | | | 70.5 | | | | (70.5 | ) | | (100 | %) | | Net income (loss) attributable to common shareholders | $ | 658.2 | | | $ | 478.4 | | | $ | 179.8 | | | | 38 | % | | $ | 1,902.4 | | | $ | 1,307.5 | | | $ | 594.9 | | | 45 | % | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | $ | 1,504.3 | | | $ | 1,274.8 | | | $ | 229.5 | | | | 18 | % | | $ | 4,510.1 | | | $ | 3,616.3 | | | $ | 893.8 | | | 25 | % | | Adjusted cash flow from operations (1) | | 1,276.8 | | | | 1,082.8 | | | | 194.0 | | | | 18 | % | | | 3,827.7 | | | | 2,987.2 | | | | 840.5 | | | 28 | % | | Adjusted free cash flow (1) | | 33.6 | | | | 172.8 | | | | (139.2 | ) | | | (81 | %) | | | 466.8 | | | | 491.4 | | | | (24.6 | ) | | (5 | %) |

| (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, 2026 Compared to Three Months Ended September 30, 2025_

The increase in commodity sales reflected higher NGL, natural gas and condensate prices ($801.5 million), higher NGL, natural gas and condensate volumes ($383.0 million) and the favorable impact of hedges ($68.5 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 NGL and natural gas prices, and 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, 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, the impact of system expansions on our asset base and higher amortization of right-of-use assets for finance leases.

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

Other, net, primarily includes the change in fair value of a contingent consideration liability related to the Dovetail Acquisition in the fourth quarter of 2025.

The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income, partially offset by the increase in excess tax-deductible stock compensation.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The increase in commodity sales reflected higher NGL, natural gas and condensate volumes ($1,279.6 million) and higher NGL and condensate prices ($562.0 million), partially offset by lower natural gas prices ($996.3 million) and the unfavorable impact of hedges ($175.5 million).

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

Product purchases and fuel were relatively flat which reflected higher NGL and natural gas volumes and higher NGL prices, partially offset by lower natural gas prices.

The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes 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, the impact of system expansions on our asset base and higher amortization of right-of-use assets for finance leases.

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 our carbon capture and sequestration activities, and lower asset abandonment costs.

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

Other, net, primarily includes the change in fair value of a contingent consideration liability related to the Dovetail Acquisition in the fourth quarter of 2025.

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 September 30, | | | | | | | | | | Nine Months Ended September 30, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2026 | | | 2025 | | | 2026 vs. 2025 | | | 2026 | | | 2025 | | | 2026 vs. 2025 | | | | | | | | | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | $ | | 813.6 | | | $ | | 637.6 | | | $ | | 176.0 | | | | 28 | % | | $ | | 2,249.7 | | | $ | | 1,827.4 | | | $ | | 422.3 | | | | 23 | % | | Operating expenses | | | 256.3 | | | | | 236.1 | | | | | 20.2 | | | | 9 | % | | | | 730.8 | | | | | 663.7 | | | | | 67.1 | | | | 10 | % | | Adjusted operating margin | $ | | 1,069.9 | | | $ | | 873.7 | | | $ | | 196.2 | | | | 22 | % | | $ | | 2,980.5 | | | $ | | 2,491.1 | | | $ | | 489.4 | | | | 20 | % | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 3,472.8 | | | | | 3,246.0 | | | | | 226.8 | | | | 7 | % | | | | 3,341.2 | | | | | 3,113.5 | | | | | 227.7 | | | | 7 | % | | Permian Delaware | | | 4,063.8 | | | | | 3,375.6 | | | | | 688.2 | | | | 20 | % | | | | 3,813.0 | | | | | 3,190.6 | | | | | 622.4 | | | | 20 | % | | Total Permian | | | 7,536.6 | | | | | 6,621.6 | | | | | 915.0 | | | | 14 | % | | | | 7,154.2 | | | | | 6,304.1 | | | | | 850.1 | | | | 13 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | | 990.8 | | | | | 1,071.0 | | | | | (80.2 | ) | | | (7 | %) | | | | 1,009.2 | | | | | 1,047.6 | | | | | (38.4 | ) | | | (4 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | | 149.7 | | | | | 129.9 | | | | | 19.8 | | | | 15 | % | | | | 136.9 | | | | | 132.5 | | | | | 4.4 | | | | 3 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 579.2 | | | | | 445.9 | | | | | 133.3 | | | | 30 | % | | | | 568.0 | | | | | 414.6 | | | | | 153.4 | | | | 37 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 9,256.3 | | | | | 8,268.4 | | | | | 987.9 | | | | 12 | % | | | | 8,868.3 | | | | | 7,898.8 | | | | | 969.5 | | | | 12 | % | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 516.8 | | | | | 478.3 | | | | | 38.5 | | | | 8 | % | | | | 496.0 | | | | | 452.8 | | | | | 43.2 | | | | 10 | % | | Permian Delaware | | | 547.5 | | | | | 452.2 | | | | | 95.3 | | | | 21 | % | | | | 506.2 | | | | | 408.8 | | | | | 97.4 | | | | 24 | % | | Total Permian | | | 1,064.3 | | | | | 930.5 | | | | | 133.8 | | | | 14 | % | | | | 1,002.2 | | | | | 861.6 | | | | | 140.6 | | | | 16 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | | 112.1 | | | | | 111.1 | | | | | 1.0 | | | | 1 | % | | | | 110.8 | | | | | 109.7 | | | | | 1.1 | | | | 1 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | | 19.0 | | | | | 16.6 | | | | | 2.4 | | | | 14 | % | | | | 17.4 | | | | | 16.5 | | | | | 0.9 | | | | 5 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 39.3 | | | | | 36.9 | | | | | 2.4 | | | | 7 | % | | | | 38.6 | | | | | 33.8 | | | | | 4.8 | | | | 14 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 1,234.7 | | | | | 1,095.1 | | | | | 139.6 | | | | 13 | % | | | | 1,169.0 | | | | | 1,021.6 | | | | | 147.4 | | | | 14 | % | | Crude oil gathered, MBbl/d | | | 152.9 | | | | | 109.8 | | | | | 43.1 | | | | 39 | % | | | | 144.0 | | | | | 120.7 | | | | | 23.3 | | | | 19 | % | | Natural gas sales, BBtu/d (3) | | | 3,352.8 | | | | | 2,930.8 | | | | | 422.0 | | | | 14 | % | | | | 3,158.9 | | | | | 2,782.3 | | | | | 376.6 | | | | 14 | % | | NGL sales, MBbl/d (3) | | | 719.1 | | | | | 634.8 | | | | | 84.3 | | | | 13 | % | | | | 675.6 | | | | | 604.1 | | | | | 71.5 | | | | 12 | % | | Condensate sales, MBbl/d | | | 22.8 | | | | | 18.0 | | | | | 4.8 | | | | 27 | % | | | | 22.3 | | | | | 18.7 | | | | | 3.6 | | | | 19 | % | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | | 1.61 | | | | | 1.20 | | | | | 0.41 | | | | 34 | % | | | | (0.04 | ) | | | | 1.45 | | | | | (1.49 | ) | | | (103 | %) | | NGL, $/gal | | | 0.50 | | | | | 0.39 | | | | | 0.11 | | | | 28 | % | | | | 0.46 | | | | | 0.43 | | | | | 0.03 | | | | 7 | % | | Condensate, $/Bbl | | | 78.79 | | | | | 67.75 | | | | | 11.04 | | | | 16 | % | | | | 78.62 | | | | | 67.78 | | | | | 10.84 | | | | 16 | % |