Targa Resources Corp. Reports Second Quarter 2025 Financial Results

2025-08-07

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

HOUSTON, Aug. 07, 2025 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported second quarter 2025 results.

Second quarter 2025 net income attributable to Targa Resources Corp. was $629.1 million compared to $298.5 million for the second quarter of 2024. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) ( 1) of $1,163.0 million for the second quarter of 2025 compared to $984.3 million for the second quarter of 2024.

Highlights

Adjusted EBITDA for the second quarter of $1.16 billion, an 18% increase year over year Record Permian and NGL transportation volumes during the second quarter Repurchased $324 million of common shares during the second quarter Expect early completion of its Pembrook II plant in Permian Midland in August Expect early completion of its Bull Moose II plant in Permian Delaware, its Delaware Express Pipeline, and its Train 11 fractionator in Mont Belvieu, Texas Announced a 43-mile extension of Targa’s Bull Run natural gas pipeline (the “Bull Run Extension”) to enhance natural gas connectivity from Targa’s Permian Delaware system to WAHA Continue to estimate full year 2025 adjusted EBITDA between $4.65 billion and $4.85 billion Estimate 2025 net growth capital expenditures of approximately $3.0 billion from the acceleration of several projects and the Bull Run Extension Announced a new $1.0 billion common share repurchase program

On July 10, 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 second quarter of 2025. Total cash dividends of approximately $215 million will be paid on August 15, 2025 on all outstanding shares of common stock to holders of record as of the close of business on July 31, 2025.

During the second quarter of 2025, Targa repurchased 1.96 million shares of its common stock at a weighted average per share price of $165.86 for a total net cost of $324.3 million. As of June 30, 2025, there was $566.2 million remaining under the Company’s $1.0 billion common share repurchase program. In August 2025, the Company’s Board of Directors approved a new share repurchase program for the repurchase of up to $1.0 billion of the Company’s outstanding common stock. The amount authorized under the new share repurchase program is in addition to the amount remaining under the existing share repurchase program.

Second Quarter 2025 - Sequential Quarter over Quarter Commentary

Targa’s reported second quarter adjusted EBITDA of $1,163.0 million was relatively flat compared to the first quarter despite the planned turnaround at Targa’s fractionation facilities in Mont Belvieu, Texas, which reduced operating capacity through much of the second quarter. Second quarter adjusted EBITDA benefited from record Permian and NGL transportation volumes, offset by lower marketing margin, lower commodity prices and higher operating expenses.

In the Gathering and Processing (“G&P”) segment, adjusted operating margin was approximately flat driven by strong growth in Permian natural gas inlet volumes and higher recoveries, offset by significantly lower commodity prices compared to the first quarter.

In the Logistics and Transportation (“L&T”) segment, adjusted operating margin was sequentially flat as record NGL pipeline transportation volumes were offset by lower marketing margin and lower fractionation volumes. Increasing NGL pipeline transportation volumes were attributable to higher supply volumes from Targa’s Permian G&P systems. Lower sequential marketing margin was attributable to fewer optimization opportunities. Fractionation volumes were lower in the second quarter due to the planned turnaround at Targa’s fractionation facilities in Mont Belvieu from March until early June, partially offset by higher Permian supply volumes.

Capitalization, Financing and Liquidity

The Company’s total consolidated debt as of June 30, 2025 was $16,850.5 million, net of $117.4 million of debt issuance costs and $38.0 million of unamortized discount, with $16,034.4 million of outstanding senior unsecured notes, $667.0 million outstanding under the Commercial Paper Program, and $304.5 million of finance lease liabilities.

In June 2025, Targa completed an underwritten public offering of 4.900% Notes due 2030 and 5.650% Notes due 2036, resulting in net proceeds of approximately $1.5 billion. Targa used the net proceeds from the debt issuance to redeem the 6.500% Notes due 2027 in July 2025 and the remaining net proceeds for general corporate purposes, including repayment of borrowings under the Commercial Paper Program.

Total consolidated liquidity as of June 30, 2025 was approximately $3.5 billion, including $2.8 billion available under the TRGP Revolver, $600.0 million under the Securitization Facility and $113.1 million of cash.

In July 2025, the Company extended the maturity of its Securitization Facility to August 31, 2026.

Growth Projects Update

In Targa’s G&P segment, the Company expects early completion of its new 275 million cubic feet per day (“MMcf/d”) Pembrook II plant in Permian Midland in August 2025. Construction continues on Targa’s 275 MMcf/d East Pembrook and East Driver plants in Permian Midland, and its 275 MMcf/d Bull Moose II and Falcon II plants in Permian Delaware. The Company now expects its Bull Moose II plant to begin operations in the fourth quarter of 2025, earlier than previously expected, and remains on-track to complete its other announced expansions as previously disclosed. Additionally, to accommodate future growth across Targa’s Permian G&P systems, the Company is moving forward with acquiring long-lead items for its next gas processing expansions in the Permian.

In Targa’s L&T segment, construction continues on its Delaware Express Pipeline expansion, its 150 thousand barrels per day (“MBbl/d”) Train 11 and Train 12 fractionators in Mont Belvieu, and its GPMT LPG Export Expansion. The Company now expects both its Delaware Express Pipeline and Train 11 fractionator to begin operations in the second quarter of 2026, earlier than previously expected, and remains on-track to complete its other announced expansions as previously disclosed.

In August 2025, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced a 43-mile extension of its Bull Run intrastate natural gas pipeline in the Permian Delaware to expand its existing connectivity to WAHA. The Bull Run Extension is expected to begin operations in the first quarter of 2027.

2025 Outlook

Targa continues to estimate full year 2025 adjusted EBITDA to be between $4.65 billion and $4.85 billion supported by forecasted growth across its Permian G&P footprint, which is expected to drive record Permian, NGL pipeline transportation, fractionation, and LPG export volumes in 2025 relative to records set in 2024. Based on current positive Permian volume trends, the Company expects to be positioned well for continued momentum in the second half of 2025 and into 2026.

With today’s announcement of earlier than expected completion of several projects, the Bull Run Extension and incremental spending for Targa’s next Permian gas processing expansions, the Company now estimates total net growth capital expenditures for 2025 of approximately $3.0 billion. Targa’s estimate for 2025 net maintenance capital expenditures remains unchanged at approximately $250 million.

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 August 7, 2025 to discuss its second 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/vkst8uaw . A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

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 .

(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, | | | | | | | | | | | | | | | | | | | | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | $ | 3,636.3 | | | $ | 2,966.7 | | | $ | 669.6 | | | 23 | % | | $ | 7,520.7 | | | $ | 6,909.3 | | | $ | 611.4 | | | 9 | % | | Fees from midstream services | | 623.8 | | | | 595.3 | | | | 28.5 | | | 5 | % | | | 1,300.9 | | | | 1,215.1 | | | | 85.8 | | | 7 | % | | Total revenues | | 4,260.1 | | | | 3,562.0 | | | | 698.1 | | | 20 | % | | | 8,821.6 | | | | 8,124.4 | | | | 697.2 | | | 9 | % | | Product purchases and fuel | | 2,436.0 | | | | 2,197.4 | | | | 238.6 | | | 11 | % | | | 5,693.8 | | | | 5,415.4 | | | | 278.4 | | | 5 | % | | Operating expenses | | 323.6 | | | | 290.7 | | | | 32.9 | | | 11 | % | | | 627.2 | | | | 568.7 | | | | 58.5 | | | 10 | % | | Depreciation and amortization expense | | 373.7 | | | | 348.6 | | | | 25.1 | | | 7 | % | | | 741.3 | | | | 689.1 | | | | 52.2 | | | 8 | % | | General and administrative expense | | 95.0 | | | | 98.3 | | | | (3.3 | ) | | (3 | %) | | | 189.5 | | | | 184.8 | | | | 4.7 | | | 3 | % | | Other operating (income) expense | | (1.8 | ) | | | (0.2 | ) | | | (1.6 | ) | | NM | | | | (7.1 | ) | | | (0.3 | ) | | | (6.8 | ) | NM | | | | Income (loss) from operations | | 1,033.6 | | | | 627.2 | | | | 406.4 | | | 65 | % | | | 1,576.9 | | | | 1,266.7 | | | | 310.2 | | | 24 | % | | Interest expense, net | | (218.4 | ) | | | (176.0 | ) | | | (42.4 | ) | | 24 | % | | | (415.5 | ) | | | (404.6 | ) | | | (10.9 | ) | | 3 | % | | Equity earnings (loss) | | 5.1 | | | | 2.9 | | | | 2.2 | | | 76 | % | | | 10.6 | | | | 5.6 | | | | 5.0 | | | 89 | % | | Other, net | | 1.0 | | | | (0.9 | ) | | | 1.9 | | | NM | | | | 1.3 | | | | 1.0 | | | | 0.3 | | | 30 | % | | Income tax (expense) benefit | | (184.1 | ) | | | (94.3 | ) | | | (89.8 | ) | | 95 | % | | | (256.3 | ) | | | (177.1 | ) | | | (79.2 | ) | | 45 | % | | Net income (loss) | | 637.2 | | | | 358.9 | | | | 278.3 | | | 78 | % | | | 917.0 | | | | 691.6 | | | | 225.4 | | | 33 | % | | Less: Net income (loss) attributable to noncontrolling interests | | 8.1 | | | | 60.4 | | | | (52.3 | ) | | (87 | %) | | | 17.4 | | | | 117.9 | | | | (100.5 | ) | | (85 | %) | | Net income (loss) attributable to Targa Resources Corp. | | 629.1 | | | | 298.5 | | | | 330.6 | | | 111 | % | | | 899.6 | | | | 573.7 | | | | 325.9 | | | 57 | % | | Premium on repurchase of noncontrolling interests, net of tax | | — | | | | — | | | | — | | | — | | | | 70.5 | | | | — | | | | 70.5 | | | 100 | % | | Net income (loss) attributable to common shareholders | $ | 629.1 | | | $ | 298.5 | | | $ | 330.6 | | | 111 | % | | $ | 829.1 | | | $ | 573.7 | | | $ | 255.4 | | | 45 | % | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | $ | 1,163.0 | | | $ | 984.3 | | | $ | 178.7 | | | 18 | % | | $ | 2,341.5 | | | $ | 1,950.8 | | | $ | 390.7 | | | 20 | % | | Adjusted cash flow from operations (1) | | 934.4 | | | | 808.5 | | | | 125.9 | | | 16 | % | | | 1,904.4 | | | | 1,547.2 | | | | 357.2 | | | 23 | % | | Adjusted free cash flow (1) | | (9.6 | ) | | | (43.0 | ) | | | 33.4 | | | 78 | % | | | 318.6 | | | | (40.0 | ) | | | 358.6 | | NM | | |

(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, 2025 Compared to Three Months Ended June 30, 2024

The increase in commodity sales reflected higher NGL volumes ($304.2 million), higher natural gas prices ($296.4 million) and the favorable impact of hedges ($290.5 million), partially offset by lower NGL and condensate prices ($217.3 million).

The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of the Company’s facilities in Mont Belvieu, Texas.

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

The increase in operating expenses was primarily due to higher labor and maintenance costs, and taxes, which were associated with system expansions and the planned turnaround at a portion of the Company’s 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 interest expense, net, was primarily due to higher borrowings in 2025.

The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.

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”).

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

The increase in commodity sales reflected higher natural gas prices ($503.7 million), higher NGL volumes ($133.8 million) and the favorable impact of hedges ($34.4 million), partially offset by lower condensate prices ($41.6 million) and lower natural gas and condensate volumes ($29.3 million).

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

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 interest expense, net, was primarily due to higher borrowings in 2025, partially offset by the recognition of cumulative interest on a legal ruling associated with the Splitter Agreement in 2024.

The increase in income tax expense was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.

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 June 30, | | | | | | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | | | | | | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | $ | 587.6 | | | $ | 572.6 | | | $ | 15.0 | | | 3 | % | | $ | 1,189.8 | | | $ | 1,128.9 | | | $ | 60.9 | | | 5 | % | | Operating expenses | | 219.4 | | | | 205.7 | | | | 13.7 | | | 7 | % | | | 427.6 | | | | 393.7 | | | | 33.9 | | | 9 | % | | Adjusted operating margin | $ | 807.0 | | | $ | 778.3 | | | $ | 28.7 | | | 4 | % | | $ | 1,617.4 | | | $ | 1,522.6 | | | $ | 94.8 | | | 6 | % | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 3,106.2 | | | | 2,866.4 | | | | 239.8 | | | 8 | % | | | 3,046.3 | | | | 2,806.3 | | | | 240.0 | | | 9 | % | | Permian Delaware | | 3,171.8 | | | | 2,805.1 | | | | 366.7 | | | 13 | % | | | 3,096.5 | | | | 2,727.0 | | | | 369.5 | | | 14 | % | | Total Permian | | 6,278.0 | | | | 5,671.5 | | | | 606.5 | | | 11 | % | | | 6,142.8 | | | | 5,533.3 | | | | 609.5 | | | 11 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX | | 381.5 | | | | 339.4 | | | | 42.1 | | | 12 | % | | | 338.5 | | | | 322.2 | | | | 16.3 | | | 5 | % | | North Texas | | 172.6 | | | | 191.8 | | | | (19.2 | ) | | (10 | %) | | | 172.1 | | | | 188.1 | | | | (16.0 | ) | | (9 | %) | | SouthOK (5) | | 322.2 | | | | 361.5 | | | | (39.3 | ) | | (11 | %) | | | 320.1 | | | | 359.3 | | | | (39.2 | ) | | (11 | %) | | WestOK | | 210.0 | | | | 215.1 | | | | (5.1 | ) | | (2 | %) | | | 205.1 | | | | 212.6 | | | | (7.5 | ) | | (4 | %) | | Total Central | | 1,086.3 | | | | 1,107.8 | | | | (21.5 | ) | | (2 | %) | | | 1,035.8 | | | | 1,082.2 | | | | (46.4 | ) | | (4 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | 130.9 | | | | 143.9 | | | | (13.0 | ) | | (9 | %) | | | 133.9 | | | | 135.5 | | | | (1.6 | ) | | (1 | %) | | Total Field | | 7,495.2 | | | | 6,923.2 | | | | 572.0 | | | 8 | % | | | 7,312.5 | | | | 6,751.0 | | | | 561.5 | | | 8 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 398.8 | | | | 467.0 | | | | (68.2 | ) | | (15 | %) | | | 398.8 | | | | 495.8 | | | | (97.0 | ) | | (20 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 7,894.0 | | | | 7,390.2 | | | | 503.8 | | | 7 | % | | | 7,711.3 | | | | 7,246.8 | | | | 464.5 | | | 6 | % | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 450.1 | | | | 424.1 | | | | 26.0 | | | 6 | % | | | 439.9 | | | | 408.4 | | | | 31.5 | | | 8 | % | | Permian Delaware | | 406.7 | | | | 364.5 | | | | 42.2 | | | 12 | % | | | 386.8 | | | | 335.7 | | | | 51.1 | | | 15 | % | | Total Permian | | 856.8 | | | | 788.6 | | | | 68.2 | | | 9 | % | | | 826.7 | | | | 744.1 | | | | 82.6 | | | 11 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX | | 39.8 | | | | 42.2 | | | | (2.4 | ) | | (6 | %) | | | 34.3 | | | | 35.6 | | | | (1.3 | ) | | (4 | %) | | North Texas | | 21.3 | | | | 23.5 | | | | (2.2 | ) | | (9 | %) | | | 21.1 | | | | 22.7 | | | | (1.6 | ) | | (7 | %) | | SouthOK (5) | | 43.0 | | | | 43.5 | | | | (0.5 | ) | | (1 | %) | | | 38.1 | | | | 35.8 | | | | 2.3 | | | 6 | % | | WestOK | | 16.1 | | | | 15.5 | | | | 0.6 | | | 4 | % | | | 15.6 | | | | 13.6 | | | | 2.0 | | | 15 | % | | Total Central | | 120.2 | | | | 124.7 | | | | (4.5 | ) | | (4 | %) | | | 109.1 | | | | 107.7 | | | | 1.4 | | | 1 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | 16.6 | | | | 18.0 | | | | (1.4 | ) | | (8 | %) | | | 16.5 | | | | 16.3 | | | | 0.2 | | | 1 | % | | Total Field | | 993.6 | | | | 931.3 | | | | 62.3 | | | 7 | % | | | 952.3 | | | | 868.1 | | | | 84.2 | | | 10 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 31.6 | | | | 34.4 | | | | (2.8 | ) | | (8 | %) | | | 32.2 | | | | 36.7 | | | | (4.5 | ) | | (12 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 1,025.2 | | | | 965.7 | | | | 59.5 | | | 6 | % | | | 984.5 | | | | 904.8 | | | | 79.7 | | | 9 | % | | Crude oil, Badlands, MBbl/d | | 90.3 | | | | 99.1 | | | | (8.8 | ) | | (9 | %) | | | 98.7 | | | | 96.8 | | | | 1.9 | | | 2 | % | | Crude oil, Permian, MBbl/d | | 26.2 | | | | 27.9 | | | | (1.7 | ) | | (6 | %) | | | 27.6 | | | | 27.7 | | | | (0.1 | ) | | — | | | Natural gas sales, BBtu/d (3) | | 2,819.5 | | | | 2,843.5 | | | | (24.0 | ) | | (1 | %) | | | 2,706.7 | | | | 2,747.0 | | | | (40.3 | ) | | (1 | %) | | NGL sales, MBbl/d (3) | | 606.4 | | | | 569.7 | | | | 36.7 | | | 6 | % | | | 588.4 | | | | 534.3 | | | | 54.1 | | | 10 | % | | Condensate sales, MBbl/d | | 20.1 | | | | 21.2 | | | | (1.1 | ) | | (5 | %) | | | 19.1 | | | | 20.1 | | | | (1.0 | ) | | (5 | %) | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | 1.01 | | | | 0.10 | | | | 0.91 | | NM | | | | 1.59 | | | | 0.78 | | | | 0.81 | | | 104 | % | | | NGL, $/gal | | 0.41 | | | | 0.44 | | | | (0.03 | ) | | (7 | %) | | | 0.46 | | | | 0.46 | | | | — | | | — | | | Condensate, $/Bbl | | 63.79 | | | | 72.83 | | | | (9.04 | ) | | (12 | %) | | | 67.80 | | | | 74.91 | | | | (7.11 | ) | | (9 | %) |