Targa Resources Corp. Reports Record Fourth Quarter and Full Year 2024 Financial Results, Provides Growth Outlook for 2025 and Announces Refinancing of Badlands Preferred Equity

2025-02-20

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

HOUSTON, Feb. 20, 2025 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported fourth quarter and full year 2024 results.

Fourth quarter 2024 net income attributable to Targa Resources Corp. was $351.0 million compared to $299.6 million for the fourth quarter of 2023. For the full year 2024, net income attributable to Targa Resources Corp. was $1,312.0 million compared to $1,345.9 million for 2023. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) ( 1) of $1,122.2 million for the fourth quarter of 2024 compared to $959.9 million for the fourth quarter of 2023. For the full year 2024, the Company reported adjusted EBITDA of $4,142.3 million compared to $3,530.0 million for 2023.

Highlights

Record full year 2024 adjusted EBITDA of $4.1 billion, a 17% increase over 2023 Record full year 2024 Permian, NGL transportation, fractionation, and LPG export volumes Record full year 2024 common share repurchases of $755 million Record fourth quarter 2024 adjusted EBITDA of $1.1 billion Record fourth quarter 2024 Permian, NGL transportation, fractionation, and LPG export volumes Completed its new 275 million cubic feet per day (“MMcf/d”) Greenwood II plant in Permian Midland and its new 120 thousand barrels per day (“MBbl/d”) Train 10 fractionator in Mont Belvieu Recently commenced operations of its new 275 MMcf/d Bull Moose plant and 800 MMcf/d front-end treater in Permian Delaware Announced a new intra-Delaware Basin expansion of Targa’s Grand Prix NGL Pipeline (“Delaware Express”) Announced a new 150 MBbl/d fractionator in Mont Belvieu (“Train 12”) Announced a new expansion of LPG export capabilities at Targa’s Galena Park Marine Terminal (“GPMT LPG Export Expansion”) which will increase capacity to approximately 19 million barrels per month (“MMBbl/month”) Estimates 2025 net growth capital expenditures of $2.6 billion to $2.8 billion Announced the refinancing of preferred equity in Targa Badlands LLC for $1.8 billion Estimates record full year 2025 adjusted EBITDA between $4.65 billion and $4.85 billion, a 15% increase over 2024 (2)

On January 16, 2025, the Company declared a quarterly cash dividend of $0.75 per common share, or $3.00 per common share on an annualized basis, for the fourth quarter of 2024. Total cash dividends of approximately $164 million were paid on February 14, 2025 on all outstanding shares of common stock to holders of record as of the close of business on January 31, 2025. Targa intends to recommend an annual common dividend of $4.00 per share for 2025 beginning with the first quarter payment in May of 2025.

Targa repurchased 610,683 shares of its common stock during the fourth quarter of 2024 at a weighted average per share price of $176.86 for a total net cost of $108.0 million. For the year ended December 31, 2024, Targa repurchased 5,933,050 shares of its common stock at a weighted average price of $127.20 for a total net cost of $754.7 million. As of December 31, 2024, there was $1,015.4 million remaining under the Company’s Share Repurchase Programs.

Fourth Quarter 2024 – Sequential Quarter over Quarter Commentary

Targa reported fourth quarter adjusted EBITDA of $1,122.2 million, representing a 5 percent increase compared to the third quarter of 2024. The sequential increase in adjusted EBITDA was attributable to higher volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems. In the G&P segment, higher sequential adjusted operating margin was attributable to record Permian natural gas inlet volumes and higher fees, partially offset by the expiration of a lower margin high pressure gathering and processing agreement in the Delaware Basin. In the L&T segment, record NGL pipeline transportation, fractionation, and LPG export volumes drove the sequential increase in segment adjusted operating margin, partially offset by lower sequential marketing margin. Targa’s completion of its Daytona NGL Pipeline late in the third quarter and its 120 MBbl/d Train 10 fractionator in the fourth quarter supported higher sequential NGL pipeline transportation and fractionation volumes from increasing supply volumes from Targa’s Permian G&P systems. LPG export volumes benefited from improved market conditions. Lower sequential marketing margin was attributable to decreased optimization opportunities.

Capitalization and Liquidity

The Company’s total consolidated debt as of December 31, 2024 was $14,174.6 million, net of $89.0 million of debt issuance costs and $29.4 million of unamortized discount, with $12,534.4 million of outstanding senior unsecured notes, $1,130.5 million outstanding under the Commercial Paper Program, $330.0 million outstanding under the Securitization Facility, and $298.1 million of finance lease liabilities.

Total consolidated liquidity as of December 31, 2024 was approximately $2.0 billion, including $1.6 billion available under the Existing TRGP Revolver (as defined below), $270.0 million under the Securitization Facility and $157.3 million of cash.

Financing Update

In February 2025, Targa entered into a new five-year revolving facility (the “New TRGP Revolver”) with aggregate capacity of $3.5 billion. The New TRGP Revolver replaces Targa’s $2.75 billion credit facility (“Existing TRGP Revolver”), scheduled to mature in February 2027. The additional capacity aligns with the Company’s increased scale and continued growth opportunities. Pro forma for the New TRGP Revolver, Targa’s liquidity as of December 31, 2024, was approximately $2.8 billion.

Refinancing of Badlands Preferred Equity

Targa announced today a definitive agreement to repurchase all of the outstanding preferred equity in Targa Badlands LLC (“Targa Badlands”) from funds managed by Blackstone for approximately $1.8 billion in cash (the “Repurchase”). The Repurchase represents a refinancing of higher cost preferred equity with Targa’s lower cost of debt capital, resulting in meaningful cash savings. Targa expects to close in the first quarter of 2025 with an effective date of January 1, 2025, and estimates its year-end 2025 debt to adjusted EBITDA leverage ratio will remain near the mid-point of the Company’s long-term target range.

Growth Projects Update

In Targa’s G&P segment, construction continues on its 275 MMcf/d Pembrook II, East Pembrook, and East Driver plants in Permian Midland and its 275 MMcf/d Bull Moose II and Falcon II plants in Permian Delaware. In Targa’s L&T segment, construction continues on its 150 MBbl/d Train 11 fractionator in Mont Belvieu. The Company remains on-track to complete these expansions as previously disclosed.

In February 2025, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced:

Delaware Express, a 100-mile, 30-inch diameter pipeline expansion of its Grand Prix NGL Pipeline in the Permian Delaware; Train 12, a new 150 MBbl/d fractionator in Mont Belvieu, TX; and GPMT LPG Export Expansion, an expansion of Targa’s LPG export capabilities at its Galena Park Marine Terminal to approximately 19 MMBbl per month.

Delaware Express is expected to commence operations in the third quarter of 2026, Train 12 is expected to commence operations in the first quarter of 2027, and Targa’s GPMT LPG Export Expansion is expected to commence operations in the third quarter of 2027.

2025 Outlook and Capital Return Expectations

For 2025, Targa estimates full year adjusted EBITDA to be between $4.65 billion and $4.85 billion, with the midpoint of the range representing a 15 percent increase over full year 2024 adjusted EBITDA. Targa expects to continue to benefit from meaningful 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 the records set in 2024.

Targa’s 2025 operational and financial expectations assume Waha natural gas prices average $1.55 per million British Thermal Units (“MMbtu”), natural gas liquids (“NGL”) composite barrel prices average $0.65 per gallon, and crude oil prices average $70 per barrel.

Targa’s estimate for 2025 net growth capital expenditures is between $2.6 billion to $2.8 billion and includes capital spending for the recently announced Delaware Express, Train 12, and GPMT LPG Export Expansion. Net maintenance capital expenditures for 2025 are estimated to be approximately $250 million.

For the first quarter of 2025, Targa intends to recommend to its Board of Directors an increase to its quarterly common dividend to $1.00 per common share or $4.00 per common share annualized. The recommended 33 percent common dividend per share increase, if approved, would be effective for the first quarter of 2025 and payable in May 2025. Going forward, Targa expects to be in position to continue to meaningfully increase the capital returned to shareholders through increasing common dividends per share and opportunistic repurchases of its common stock.

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

Conference Call

The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on February 20, 2025 to discuss its fourth 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/qgzvcwi7 . A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

(1) Adjusted EBITDA is a non-GAAP financial measure and is discussed under “Non-GAAP Financial Measures.” (2) Year over year increase based on midpoint of estimated 2025 adjusted EBITDA range of $4.65 billion to $4.85 billion.

Targa Resources Corp. – Consolidated Financial Results of Operations

| | | Three Months Ended December 31, | | | | | | | | | Year Ended December 31, | | | | | | | | | | | | | | | | | | | | | | | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | | $ | 3,765.5 | | | $ | 3,647.9 | | | $ | 117.6 | | | | 3 | % | | $ | 13,891.8 | | | $ | 13,962.1 | | | $ | (70.3 | ) | | | (1 | %) | | Fees from midstream services | | | 639.7 | | | | 591.6 | | | | 48.1 | | | | 8 | % | | | 2,489.7 | | | | 2,098.2 | | | | 391.5 | | | | 19 | % | | Total revenues | | | 4,405.2 | | | | 4,239.5 | | | | 165.7 | | | | 4 | % | | | 16,381.5 | | | | 16,060.3 | | | | 321.2 | | | | 2 | % | | Product purchases and fuel | | | 2,922.6 | | | | 2,898.5 | | | | 24.1 | | | | 1 | % | | | 10,703.0 | | | | 10,676.4 | | | | 26.6 | | | | — | | | Operating expenses | | | 305.8 | | | | 269.5 | | | | 36.3 | | | | 13 | % | | | 1,175.6 | | | | 1,077.9 | | | | 97.7 | | | | 9 | % | | Depreciation and amortization expense | | | 378.5 | | | | 341.4 | | | | 37.1 | | | | 11 | % | | | 1,423.0 | | | | 1,329.6 | | | | 93.4 | | | | 7 | % | | General and administrative expense | | | 97.5 | | | | 95.3 | | | | 2.2 | | | | 2 | % | | | 384.9 | | | | 348.7 | | | | 36.2 | | | | 10 | % | | Other operating (income) expense | | | 0.2 | | | | (0.5 | ) | | | 0.7 | | | NM | | | | (0.4 | ) | | | 1.5 | | | | (1.9 | ) | | NM | | | | | Income (loss) from operations | | | 700.6 | | | | 635.3 | | | | 65.3 | | | | 10 | % | | | 2,695.4 | | | | 2,626.2 | | | | 69.2 | | | | 3 | % | | Interest expense, net | | | (177.7 | ) | | | (178.0 | ) | | | 0.3 | | | | — | | | | (767.2 | ) | | | (687.8 | ) | | | (79.4 | ) | | | 12 | % | | Equity earnings (loss) | | | 1.5 | | | | 2.8 | | | | (1.3 | ) | | | (46 | %) | | | 9.4 | | | | 9.0 | | | | 0.4 | | | | 4 | % | | Gain (loss) from financing activities | | | — | | | | (2.1 | ) | | | 2.1 | | | | 100 | % | | | (0.8 | ) | | | (2.1 | ) | | | 1.3 | | | | 62 | % | | Other, net | | | 0.1 | | | | 2.1 | | | | (2.0 | ) | | NM | | | | 1.2 | | | | (2.8 | ) | | | 4.0 | | | NM | | | | | Income tax (expense) benefit | | | (110.5 | ) | | | (102.5 | ) | | | (8.0 | ) | | | 8 | % | | | (384.5 | ) | | | (363.2 | ) | | | (21.3 | ) | | | 6 | % | | Net income (loss) | | | 414.0 | | | | 357.6 | | | | 56.4 | | | | 16 | % | | | 1,553.5 | | | | 1,579.3 | | | | (25.8 | ) | | | (2 | %) | | Less: Net income (loss) attributable to noncontrolling interests | | | 63.0 | | | | 58.0 | | | | 5.0 | | | | 9 | % | | | 241.5 | | | | 233.4 | | | | 8.1 | | | | 3 | % | | Net income (loss) attributable to Targa Resources Corp. | | | 351.0 | | | | 299.6 | | | | 51.4 | | | | 17 | % | | | 1,312.0 | | | | 1,345.9 | | | | (33.9 | ) | | | (3 | %) | | Premium on repurchase of noncontrolling interests, net of tax | | | 32.9 | | | | 19.4 | | | | 13.5 | | | | 70 | % | | | 32.9 | | | | 510.1 | | | | (477.2 | ) | | | (94 | %) | | Net income (loss) attributable to common shareholders | | $ | 318.1 | | | $ | 280.2 | | | $ | 37.9 | | | | 14 | % | | $ | 1,279.1 | | | $ | 835.8 | | | $ | 443.3 | | | | 53 | % | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | | $ | 1,122.2 | | | $ | 959.9 | | | $ | 162.3 | | | | 17 | % | | $ | 4,142.3 | | | $ | 3,530.0 | | | $ | 612.3 | | | | 17 | % | | Adjusted cash flow from operations (1) | | | 940.9 | | | | 780.1 | | | | 160.8 | | | | 21 | % | | | 3,372.4 | | | | 2,840.6 | | | | 531.8 | | | | 19 | % | | Adjusted free cash flow (1) | | | 56.2 | | | | 73.7 | | | | (17.5 | ) | | | (24 | %) | | | 140.1 | | | | 392.7 | | | | (252.6 | ) | | | (64 | %) |

| (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 December 31, 2024 Compared to Three Months Ended December 31, 2023 _

The increase in commodity sales reflects higher NGL, natural gas and condensate volumes ($242.4) and higher NGL prices ($199.5 million), partially offset by lower natural gas and condensate prices ($197.0 million) and the unfavorable impact of hedges ($127.3 million).

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

Product purchases and fuel are relatively flat reflecting higher NGL and natural gas volumes, offset by lower natural gas prices.

The increase in operating expenses is primarily due to higher maintenance and labor costs as a result of increased activity and system expansions, partially offset by lower taxes.

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

The increase in depreciation and amortization expense is primarily due to the impact of system expansions on the Company’s asset base that have been placed in service during 2024.

The increase in income tax expense is primarily due to an increase in pre-tax book income and the release of state valuation allowance in 2023 partially offset by the impact of statutory rate changes.

The premium on repurchase of noncontrolling interests, net of tax is primarily due to the CBF Acquisition in 2024.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Commodity sales are relatively flat reflecting lower natural gas and condensate prices ($1,242.8 million) and the unfavorable impact of hedges ($686.5 million), offset by higher NGL, natural gas and condensate volumes ($1,607.2 million), and higher NGL prices ($251.6 million).

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

Product purchases and fuel are relatively flat reflecting higher NGL and natural gas volumes, offset by lower natural gas prices.

The increase in operating expenses is primarily due to higher labor, maintenance, rental and chemical costs as a result of increased activity and system expansions, partially offset by lower taxes.

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

The increase in depreciation and amortization expense is primarily due to the impact of system expansions on the Company’s asset base, partially offset by the shortening of depreciable lives of certain assets that were idled in 2023.

The increase in general and administrative expense is primarily due to higher compensation and benefits and professional fees.

The increase in interest expense, net, is due to recognition of cumulative interest on a 2024 legal ruling associated with the Splitter Agreement and higher borrowings, partially offset by higher capitalized interest. Higher capitalized interest is due to system expansions and higher interest rates.

The increase in income tax expense is primarily due to the release of state valuation allowance in 2023.

The premium on repurchase of noncontrolling interests, net of tax is primarily due to the CBF Acquisition in 2024 and the Grand Prix Transaction in 2023.

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 December 31, | | | | | | | | | | Year Ended December 31, | | | | | | | | | | | | | | | | | | | | | | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | | $ | 598.9 | | | $ | 536.3 | | | $ | 62.6 | | | | 12 | % | | $ | 2,312.4 | | | $ | 2,082.2 | | | $ | 230.2 | | | | 11 | % | | Operating expenses | | | 217.5 | | | | 185.7 | | | | 31.8 | | | | 17 | % | | | 814.6 | | | | 746.6 | | | | 68.0 | | | | 9 | % | | Adjusted operating margin | | $ | 816.4 | | | $ | 722.0 | | | $ | 94.4 | | | | 13 | % | | $ | 3,127.0 | | | $ | 2,828.8 | | | $ | 298.2 | | | | 11 | % | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 3,072.8 | | | | 2,716.5 | | | | 356.3 | | | | 13 | % | | | 2,933.1 | | | | 2,535.2 | | | | 397.9 | | | | 16 | % | | Permian Delaware | | | 2,992.4 | | | | 2,564.3 | | | | 428.1 | | | | 17 | % | | | 2,837.3 | | | | 2,526.5 | | | | 310.8 | | | | 12 | % | | Total Permian | | | 6,065.2 | | | | 5,280.8 | | | | 784.4 | | | | 15 | % | | | 5,770.4 | | | | 5,061.7 | | | | 708.7 | | | | 14 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX | | | 329.4 | | | | 347.9 | | | | (18.5 | ) | | | (5 | %) | | | 325.9 | | | | 367.4 | | | | (41.5 | ) | | | (11 | %) | | North Texas | | | 187.4 | | | | 207.7 | | | | (20.3 | ) | | | (10 | %) | | | 186.9 | | | | 205.9 | | | | (19.0 | ) | | | (9 | %) | | SouthOK (5) | | | 339.7 | | | | 366.5 | | | | (26.8 | ) | | | (7 | %) | | | 351.7 | | | | 385.0 | | | | (33.3 | ) | | | (9 | %) | | WestOK | | | 210.5 | | | | 207.1 | | | | 3.4 | | | | 2 | % | | | 212.8 | | | | 207.1 | | | | 5.7 | | | | 3 | % | | Total Central | | | 1,067.0 | | | | 1,129.2 | | | | (62.2 | ) | | | (6 | %) | | | 1,077.3 | | | | 1,165.4 | | | | (88.1 | ) | | | (8 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | | 128.8 | | | | 131.2 | | | | (2.4 | ) | | | (2 | %) | | | 136.3 | | | | 130.0 | | | | 6.3 | | | | 5 | % | | Total Field | | | 7,261.0 | | | | 6,541.2 | | | | 719.8 | | | | 11 | % | | | 6,984.0 | | | | 6,357.1 | | | | 626.9 | | | | 10 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 405.7 | | | | 567.0 | | | | (161.3 | ) | | | (28 | %) | | | 449.6 | | | | 541.1 | | | | (91.5 | ) | | | (17 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 7,666.7 | | | | 7,108.2 | | | | 558.5 | | | | 8 | % | | | 7,433.6 | | | | 6,898.2 | | | | 535.4 | | | | 8 | % | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 445.7 | | | | 398.3 | | | | 47.4 | | | | 12 | % | | | 428.4 | | | | 367.7 | | | | 60.7 | | | | 17 | % | | Permian Delaware | | | 390.2 | | | | 310.6 | | | | 79.6 | | | | 26 | % | | | 359.9 | | | | 321.6 | | | | 38.3 | | | | 12 | % | | Total Permian | | | 835.9 | | | | 708.9 | | | | 127.0 | | | | 18 | % | | | 788.3 | | | | 689.3 | | | | 99.0 | | | | 14 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX (5) | | | 29.3 | | | | 37.3 | | | | (8.0 | ) | | | (21 | %) | | | 32.8 | | | | 40.9 | | | | (8.1 | ) | | | (20 | %) | | North Texas | | | 22.9 | | | | 24.5 | | | | (1.6 | ) | | | (7 | %) | | | 22.6 | | | | 24.0 | | | | (1.4 | ) | | | (6 | %) | | SouthOK (5) | | | 40.1 | | | | 40.0 | | | | 0.1 | | | | — | | | | 35.0 | | | | 43.1 | | | | (8.1 | ) | | | (19 | %) | | WestOK | | | 16.3 | | | | 12.1 | | | | 4.2 | | | | 35 | % | | | 15.1 | | | | 12.5 | | | | 2.6 | | | | 21 | % | | Total Central | | | 108.6 | | | | 113.9 | | | | (5.3 | ) | | | (5 | %) | | | 105.5 | | | | 120.5 | | | | (15.0 | ) | | | (12 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | | 15.3 | | | | 15.7 | | | | (0.4 | ) | | | (3 | %) | | | 16.6 | | | | 15.5 | | | | 1.1 | | | | 7 | % | | Total Field | | | 959.8 | | | | 838.5 | | | | 121.3 | | | | 14 | % | | | 910.4 | | | | 825.3 | | | | 85.1 | | | | 10 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 36.0 | | | | 43.2 | | | | (7.2 | ) | | | (17 | %) | | | 35.8 | | | | 39.2 | | | | (3.4 | ) | | | (9 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 995.8 | | | | 881.7 | | | | 114.1 | | | | 13 | % | | | 946.2 | | | | 864.5 | | | | 81.7 | | | | 9 | % | | Crude oil, Badlands, MBbl/d | | | 110.1 | | | | 105.2 | | | | 4.9 | | | | 5 | % | | | 106.6 | | | | 105.5 | | | | 1.1 | | | | 1 | % | | Crude oil, Permian, MBbl/d | | | 29.5 | | | | 27.5 | | | | 2.0 | | | | 7 | % | | | 27.9 | | | | 27.4 | | | | 0.5 | | | | 2 | % | | Natural gas sales, BBtu/d (3) | | | 2,784.3 | | | | 2,737.3 | | | | 47.0 | | | | 2 | % | | | 2,780.5 | | | | 2,685.8 | | | | 94.7 | | | | 4 | % | | NGL sales, MBbl/d (3) | | | 582.0 | | | | 520.6 | | | | 61.4 | | | | 12 | % | | | 558.2 | | | | 495.8 | | | | 62.4 | | | | 13 | % | | Condensate sales, MBbl/d | | | 19.8 | | | | 17.8 | | | | 2.0 | | | | 11 | % | | | 19.3 | | | | 18.5 | | | | 0.8 | | | | 4 | % | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | | 1.04 | | | | 1.83 | | | | (0.79 | ) | | | (43 | %) | | | 0.67 | | | | 1.94 | | | | (1.27 | ) | | | (65 | %) | | NGL, $/gal | | | 0.49 | | | | 0.43 | | | | 0.06 | | | | 14 | % | | | 0.46 | | | | 0.46 | | | | — | | | | — | | | Condensate, $/Bbl | | | 66.83 | | | | 74.79 | | | | (7.96 | ) | | | (11 | %) | | | 73.35 | | | | 74.35 | | | | (1.00 | ) | | | (1 | %) |