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Targa Resources Corp. Reports Third Quarter 2026 Financial Results and Announces Expectation for a 20% Increase to its 2027 Common Dividend
HOUSTON - November 5, 2026 - 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”) 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% |
(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, 2026 | Three Months Ended September 30, 2025 |
|---|
| (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) | 7.3 | $1.740 | $12.7 | 7.5 | $1.613 | $12.1 |
| NGL (MMgal) | 109.3 | (0.068) | (7.4) | 69.3 | 0.038 | 2.6 |
| Crude oil (MBbl) | 0.8 | (16.250) | (13.0) | 0.7 | 6.286 | 4.4 |
| | | $(7.7) | | | $19.1 |
| Nine Months Ended September 30, 2026 | Nine Months Ended September 30, 2025 |
|---|
| (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) | 23.4 | $3.030 | $70.9 | 22.6 | $1.549 | $35.0 |
| NGL (MMgal) | 317.9 | (0.038) | (12.0) | 250.5 | (0.018) | (4.4) |
| Crude oil (MBbl) | 2.3 | (14.826) | (34.1) | 2.1 | 5.000 | 10.5 |
| | | $24.8 | | | $41.1 |
(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, 2026 Compared to Three Months Ended September 30, 2025
The increase in adjusted operating margin was primarily due to higher natural gas inlet volumes in the Permian which drove higher fee-based margin. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Bull Moose II plant during the fourth quarter of 2025, the Falcon II and East Pembrook plants during the first quarter of 2026, the East Driver plant during the second quarter of 2026, continued strong producer activity and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
The increase in operating expenses was primarily due to higher volumes resulting from multiple plant additions and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
The increase in adjusted operating margin was primarily due to higher natural gas inlet volumes in the Permian which drove higher fee-based margin, partially offset by lower natural gas prices. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Bull Moose II plant during the fourth quarter of 2025, the Falcon II and East Pembrook plants during the first quarter of 2026, the East Driver plant during the second quarter of 2026, continued strong producer activity and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
The increase in operating expenses was primarily due to higher volumes resulting from multiple plant additions and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
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, | | |
|---|
| 2026 | 2025 | 2026 vs. 2025 | 2026 | 2025 | 2026 vs. 2025 |
|---|
| (In millions, except operating statistics) |
|---|
| Operating margin | $771.0 | $710.2 | $60.8 | 9% | $2,492.6 | $1,989.3 | $503.3 | 25% |
| Operating expenses | 117.1 | 98.6 | 18.5 | 19% | 331.6 | 299.5 | 32.1 | 11% |
| Adjusted operating margin | $888.1 | $808.8 | $79.3 | 10% | $2,824.2 | $2,288.8 | $535.4 | 23% |
| Operating statistics MBbl/d (1): | | | | | | | | |
| NGL pipeline transportation volumes (2) | 1,171.7 | 1,017.0 | 154.7 | 15% | 1,096.4 | 941.2 | 155.2 | 16% |
| Fractionation volumes | 1,261.5 | 1,134.3 | 127.2 | 11% | 1,204.7 | 1,028.3 | 176.4 | 17% |
| Export volumes (3) | 447.9 | 407.4 | 40.5 | 10% | 457.4 | 425.9 | 31.5 | 7% |
| NGL sales | 1,367.7 | 1,249.3 | 118.4 | 9% | 1,327.8 | 1,195.8 | 132.0 | 11% |
(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.
(2) Represents the total quantity of mixed NGLs that earn a transportation margin.
(3) Export volumes represent the quantity of NGL products delivered to third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets.
Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025
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 and the addition of Train 11 in the second quarter of 2026. Marketing margin increased due to greater optimization opportunities.
The increase in operating expenses was primarily due to higher repairs and maintenance and compensation and benefits including costs related to system expansions.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
The increase in adjusted operating margin was due to higher marketing margin and higher pipeline transportation and fractionation margin. Marketing margin increased due to greater optimization opportunities. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and the addition of Train 11 in the second quarter of 2026.
The increase in operating expenses was primarily due to higher compensation and benefits, repairs and maintenance, and taxes including costs related to system expansions.
Other
| Three Months Ended September 30, | | Nine Months Ended September 30, | |
|---|
| 2026 | 2025 | 2026 vs. 2025 | 2026 | 2025 | 2026 vs. 2025 |
|---|
| (In millions) |
|---|
| Operating margin | $63.1 | $(36.5) | $99.6 | $55.9 | $(4.8) | $60.7 |
| Adjusted operating margin | $63.1 | $(36.5) | $99.6 | $55.9 | $(4.8) | $60.7 |
Other contains the unrealized 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; and revenues 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; and
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for 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; and the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for 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, |
|---|
| 2026 | 2025 | 2026 | 2025 |
|---|
| (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. | $658.2 | $478.4 | $1,902.4 | $1,378.0 |
| Interest (income) expense, net | 232.8 | 221.3 | 697.0 | 636.8 |
| Income tax expense (benefit) | 174.7 | 134.3 | 525.8 | 390.6 |
| Depreciation and amortization expense | 459.6 | 383.5 | 1,338.7 | 1,124.8 |
| (Gain) loss on sale or disposition of assets | (3.6) | (4.2) | (5.4) | (5.4) |
| Write-down of assets | 2.4 | 1.5 | 7.4 | 13.1 |
| (Gain) loss from financing activities | 0.1 | 1.9 | 10.2 | 2.5 |
| Equity (earnings) loss | (10.2) | (6.4) | (26.6) | (17.0) |
| Distributions from unconsolidated affiliates | 8.1 | 7.6 | 20.0 | 18.7 |
| Change in contingent consideration | 22.6 | - | 23.8 | - |
| Compensation on equity grants | 17.4 | 17.5 | 58.6 | 52.2 |
| Risk management activities | (63.1) | 36.5 | (55.9) | 4.8 |
| Noncontrolling interests adjustments (1) | 5.3 | 2.9 | 14.1 | 8.6 |
| Litigation and environmental reserves (2) | - | - | - | 8.6 |
| Adjusted EBITDA | $1,504.3 | $1,274.8 | $4,510.1 | $3,616.3 |
| Interest expense on debt obligations (3) | (227.1) | (216.5) | (681.3) | (624.0) |
| Cash tax (expense) benefit | (0.4) | 24.5 | (1.1) | (5.1) |
| Adjusted Cash Flow from Operations | $1,276.8 | $1,082.8 | $3,827.7 | $2,987.2 |
| Maintenance capital expenditures, net (4) | (57.2) | (57.0) | (147.2) | (163.2) |
| Growth capital expenditures, net (4) | (1,186.0) | (853.0) | (3,213.7) | (2,332.6) |
| Adjusted Free Cash Flow | $33.6 | $172.8 | $466.8 | $491.4 |
(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 and environmental reserves includes charges related to specific litigation and environmental compliance matters that are nonrecurring in nature and 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 these charges as we do not consider them reflective of our ongoing core operations.
(3) Excludes amortization recognized in interest expense.
(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 2026:
| 2026E |
|---|
| (In millions) |
|---|
| Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to | |
| Estimated Adjusted EBITDA | |
| Net income attributable to Targa Resources Corp. | $2,490.0 |
| Interest expense, net | 940.0 |
| Income tax expense | 720.0 |
| Depreciation and amortization expense | 1,790.0 |
| Equity earnings | (35.0) |
| Distributions from unconsolidated affiliates | 30.0 |
| Compensation on equity grants | 80.0 |
| Risk management activities and other | (25.0) |
| Noncontrolling interests adjustments (1) | 10.0 |
| Estimated Adjusted EBITDA | $6,000.0 |
(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
Forward-looking statements notice
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, payment of future dividends and stock repurchase activity. 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, including the Company’s realization of the expected benefits of long-term commercial agreements, 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, 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 Relations
InvestorRelations@targaresources.com
(713) 584-1133