Targa Resources Corp. Reports Record Second Quarter 2024 Results and Increases Full Year 2024 Outlook

2024-08-01

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

HOUSTON, Aug. 01, 2024 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported second quarter 2024 results.

Second quarter 2024 net income attributable to Targa Resources Corp. was $298.5 million compared to $329.3 million for the second quarter of 2023. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) (1) of $984.3 million for the second quarter of 2024 compared to $789.1 million for the second quarter of 2023.

Highlights

Record adjusted EBITDA for the second quarter of $984.3 million Record Permian, NGL transportation, and fractionation volumes during the second quarter Repurchased a quarterly record $355.1 million of common stock during the second quarter Announced a new $1.0 billion common share repurchase program Estimate 2024 adjusted EBITDA to be $3.95 billion to $4.05 billion, a 5% increase over its previous estimate Announced two new 275 million cubic feet per day (“MMcf/d”) gas plants in the Permian Basin Estimate 2024 net growth capital expenditures of approximately $2.7 billion due to the acceleration of spend attributable to higher anticipated volume growth on Targa’s Permian systems

On July 11, 2024, 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 second quarter of 2024. Total cash dividends of approximately $164 million will be paid on August 15, 2024 on all outstanding shares of common stock to holders of record as of the close of business on July 31, 2024.

Targa repurchased 2,985,816 shares of its common stock during the second quarter of 2024 at a weighted average per share price of $118.91 for a total net cost of $355.1 million. There was $291.3 million remaining under the Company’s $1.0 billion common share repurchase program as of June 30, 2024. In July 2024, 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 2024 - Sequential Quarter over Quarter Commentary

Targa reported record second quarter adjusted EBITDA of $984.3 million, representing a 2 percent increase compared to the first 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, higher recoveries, and higher fees. In the L&T segment, record NGL pipeline transportation and fractionation volumes drove the sequential increase in segment adjusted operating margin. Increasing NGL pipeline transportation and fractionation volumes were attributable to higher supply volumes from Targa’s Permian G&P systems. Higher segment operating expenses were attributable to higher system volumes and expansions and higher general and administrative expenses were attributable to higher compensation and benefits.

Capitalization and Liquidity

The Company’s total consolidated debt as of June 30, 2024 was $13,567.0 million, net of $84.6 million of debt issuance costs and $29.5 million of unamortized discount, with $11,534.4 million of outstanding senior notes, $1,303.0 million outstanding under the Commercial Paper Program, $550.0 million outstanding under the Securitization Facility, and $293.7 million of finance lease liabilities.

Total consolidated liquidity as of June 30, 2024 was approximately $1.6 billion, including $1.4 billion available under the TRGP Revolver, $166.4 million of cash and $50.0 million available under the Securitization Facility.

Financing Update

On May 21, 2024, Targa repaid all $500.0 million outstanding under the $1.5 billion unsecured term loan facility due July 2025 (the “Term Loan Facility”). As a result of the repayment, the Company recorded a loss due to debt extinguishment of $0.8 million.

Growth Projects Update

During the second quarter, Targa commenced operations at its new 230 MMcf/d Roadrunner II plant in Permian Delaware and its new 120 MBbl/d Train 9 fractionator in Mont Belvieu, TX, on-time and on-budget. Targa expects to begin starting up operations on the reactivation of Gulf Coast Fractionators (“GCF”) in Mont Belvieu during the third quarter of 2024. In its G&P segment, construction continues on Targa’s 275 MMcf/d Greenwood II and Pembrook II plants in Permian Midland and its 275 MMcf/d Bull Moose plant in Permian Delaware. In its L&T segment, construction continues on Targa’s Daytona NGL Pipeline and its 120 MBbl/d Train 10 and 150 MBbl/d Train 11 fractionators in Mont Belvieu. Targa remains on-track to complete these expansions as previously disclosed.

In August 2024, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose II plant”) and a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “East Pembrook plant”). The Bull Moose II plant is expected to begin operations in the first quarter of 2026 and the East Pembrook plant is expected to begin operations in the third quarter of 2026.

On July 31, 2024, WhiteWater announced that WhiteWater, MPLX LP (NYSE: MPLX), and Enbridge Inc. (NYSE: ENB), through the WPC Joint Venture (“WPC”), the joint venture that owns the Whistler Pipeline, have partnered with Targa to reach final investment decision to move forward with the construction of the Blackcomb Pipeline (“Blackcomb”) after having secured sufficient firm transportation agreements with predominantly investment grade shippers. Blackcomb is designed to transport up to 2.5 billion cubic feet per day (“Bcf/d”) of natural gas through approximately 365 miles of 42-inch pipeline from the Permian Basin in West Texas to the Agua Dulce area in South Texas. Blackcomb is expected to be in service in the second half of 2026, pending the receipt of customary regulatory and other approvals. Blackcomb is a joint venture owned 70.0 percent by WPC, 17.5 percent by Targa, and 12.5 percent by MPLX.

2024 Outlook

Given the strength of volume growth across Targa’s integrated assets, the Company now expects to generate full year 2024 adjusted EBITDA of $3.95 billion to $4.05 billion, a 5 percent increase over its previous estimate. With today’s announcement related to moving ahead with the construction of its Bull Moose II and East Pembrook plants, incremental spending on related infrastructure attributable to higher volume growth on Targa’s systems in the Permian Basin, and spending on the acceleration of downstream connections and residue gas takeaway, Targa now estimates total net growth capital expenditures for 2024 to be approximately $2.7 billion. The increase from Targa’s previous estimate is attributable to the acceleration of volume growth across Targa’s Permian footprint necessitating additional G&P plant and field infrastructure that is expected to be highly utilized when it comes online bringing increasing volumes through the rest of Targa’s integrated system. Targa continues to estimate net maintenance capital expenditures for 2024 to be approximately $225 million.

Positioning in 2025

For 2025, higher volume growth across Targa’s Permian systems is expected to drive a meaningful year-over-year increase in adjusted EBITDA and higher adjusted EBITDA than previously forecasted, and a similar Free Cash Flow inflection as previously forecasted, which means the Company is well positioned to continue to provide a meaningful increase in capital returned to shareholders through increasing common dividends per share and continued common share repurchases.

Targa continues to estimate a meaningful step down in net growth capital expenditures in 2025 versus 2024 as the Company’s large downstream Daytona NGL Pipeline and Train 10 fractionator remain on-track to be completed as previously disclosed. Due to higher anticipated volume growth on Targa’s Permian systems in 2025, necessitating the acceleration of G&P plant and field capital spend in the Permian, and its newly announced equity investment in Blackcomb (which is expected to be project financed), Targa currently estimates approximately $1.7 billion of net growth capital expenditures for 2025. Spending in 2025 is largely Permian G&P focused on additional infrastructure that will be highly utilized at start-up and will bring increasing volumes through Targa’s integrated system.

For a more detailed bridge of estimated 2024 and 2025 net growth capital expenditures, please refer to slide 5 in the earnings supplement presentation available under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events. An updated investor presentation is also 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 August 1, 2024 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/9n9qxwtw . 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.” | | | |

Targa Resources Corp. – Consolidated Financial Results of Operations

| | Three Months Ended June 30, | | | | | | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | | | | | | | | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | $ | 2,991.1 | | | $ | 2,914.6 | | | $ | 76.5 | | | | 3 | % | | $ | 6,944.4 | | | $ | 6,939.7 | | | $ | 4.7 | | | | — | | | Fees from midstream services | | 570.9 | | | | 489.1 | | | | 81.8 | | | | 17 | % | | | 1,180.0 | | | | 984.5 | | | | 195.5 | | | | 20 | % | | Total revenues | | 3,562.0 | | | | 3,403.7 | | | | 158.3 | | | | 5 | % | | | 8,124.4 | | | | 7,924.2 | | | | 200.2 | | | | 3 | % | | Product purchases and fuel | | 2,197.4 | | | | 2,068.9 | | | | 128.5 | | | | 6 | % | | | 5,415.4 | | | | 5,088.0 | | | | 327.4 | | | | 6 | % | | Operating expenses | | 290.7 | | | | 272.6 | | | | 18.1 | | | | 7 | % | | | 568.7 | | | | 530.7 | | | | 38.0 | | | | 7 | % | | Depreciation and amortization expense | | 348.6 | | | | 332.1 | | | | 16.5 | | | | 5 | % | | | 689.1 | | | | 656.9 | | | | 32.2 | | | | 5 | % | | General and administrative expense | | 98.3 | | | | 81.0 | | | | 17.3 | | | | 21 | % | | | 184.8 | | | | 163.4 | | | | 21.4 | | | | 13 | % | | Other operating (income) expense | | (0.2 | ) | | | — | | | | (0.2 | ) | | | (100 | %) | | | (0.3 | ) | | | (0.6 | ) | | | 0.3 | | | | 50 | % | | Income (loss) from operations | | 627.2 | | | | 649.1 | | | | (21.9 | ) | | | (3 | %) | | | 1,266.7 | | | | 1,485.8 | | | | (219.1 | ) | | | (15 | %) | | Interest expense, net | | (176.0 | ) | | | (166.6 | ) | | | (9.4 | ) | | | 6 | % | | | (404.6 | ) | | | (334.7 | ) | | | (69.9 | ) | | | 21 | % | | Equity earnings (loss) | | 2.9 | | | | 3.4 | | | | (0.5 | ) | | | (15 | %) | | | 5.6 | | | | 3.2 | | | | 2.4 | | | | 75 | % | | Gain (loss) from financing activities | | (0.8 | ) | | | — | | | | (0.8 | ) | | | 100 | % | | | (0.8 | ) | | | — | | | | (0.8 | ) | | | 100 | % | | Other, net | | (0.1 | ) | | | (2.0 | ) | | | 1.9 | | | | 95 | % | | | 1.8 | | | | (4.9 | ) | | | 6.7 | | | | 137 | % | | Income tax (expense) benefit | | (94.3 | ) | | | (96.4 | ) | | | 2.1 | | | | 2 | % | | | (177.1 | ) | | | (206.7 | ) | | | 29.6 | | | | 14 | % | | Net income (loss) | | 358.9 | | | | 387.5 | | | | (28.6 | ) | | | (7 | %) | | | 691.6 | | | | 942.7 | | | | (251.1 | ) | | | (27 | %) | | Less: Net income (loss) attributable to noncontrolling interests | | 60.4 | | | | 58.2 | | | | 2.2 | | | | 4 | % | | | 117.9 | | | | 116.4 | | | | 1.5 | | | | 1 | % | | Net income (loss) attributable to Targa Resources Corp. | | 298.5 | | | | 329.3 | | | | (30.8 | ) | | | (9 | %) | | | 573.7 | | | | 826.3 | | | | (252.6 | ) | | | (31 | %) | | Premium on repurchase of noncontrolling interests, net of tax | | — | | | | — | | | | — | | | | — | | | | — | | | | 490.7 | | | | (490.7 | ) | | | (100 | %) | | Net income (loss) attributable to common shareholders | $ | 298.5 | | | $ | 329.3 | | | $ | (30.8 | ) | | | (9 | %) | | $ | 573.7 | | | $ | 335.6 | | | $ | 238.1 | | | | 71 | % | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | $ | 984.3 | | | $ | 789.1 | | | $ | 195.2 | | | | 25 | % | | $ | 1,950.8 | | | $ | 1,729.7 | | | $ | 221.1 | | | | 13 | % | | Adjusted cash flow from operations (1) | | 808.5 | | | | 622.0 | | | | 186.5 | | | | 30 | % | | | 1,547.2 | | | | 1,393.2 | | | | 154.0 | | | | 11 | % | | Adjusted free cash flow (1) | | (43.0 | ) | | | (3.7 | ) | | | (39.3 | ) | | NM | | | | (40.0 | ) | | | 310.3 | | | | (350.3 | ) | | | (113 | %) | |

| (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, 2024 Compared to Three Months Ended June 30, 2023

The increase in commodity sales reflects higher NGL prices ($357.7 million) and higher NGL, natural gas and condensate volumes ($272.7 million), partially offset by lower natural gas and condensate prices ($302.5 million) and the unfavorable impact of hedges ($251.6 million).

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

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

The increase in operating expenses is primarily due to higher labor and rental costs as a result of increased activity and system expansions.

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 the second quarter of 2023 and subsequently shut down in the third quarter of 2023.

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

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

Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023

The increase in commodity sales reflects higher NGL, natural gas and condensate volumes ($985.8 million) and higher NGL prices ($158.0 million), partially offset by lower natural gas prices ($632.3 million) and the unfavorable impact of hedges ($510.0 million).

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

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

The increase in operating expenses is primarily due to higher labor and rental costs as a result of increased activity and system expansions.

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

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

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 an increase in capitalized interest.

The decrease in income tax expense is primarily due to a decrease in pre-tax book income, partially offset by the release of valuation allowance in 2023.

The premium on repurchase of noncontrolling interests, net of tax is due to the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture 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 June 30, | | | | | | | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | | | | | | | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | 2024 | | | 2023 | | | 2024 vs. 2023 | | | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | $ | 572.6 | | | $ | 502.5 | | | $ | 70.1 | | | | 14 | % | | $ | 1,128.9 | | | $ | 1,040.9 | | | $ | 88.0 | | | | 8 | % | | Operating expenses | | 205.7 | | | | 189.8 | | | | 15.9 | | | | 8 | % | | | 393.7 | | | | 371.2 | | | | 22.5 | | | | 6 | % | | Adjusted operating margin | $ | 778.3 | | | $ | 692.3 | | | $ | 86.0 | | | | 12 | % | | $ | 1,522.6 | | | $ | 1,412.1 | | | $ | 110.5 | | | | 8 | % | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 2,866.4 | | | | 2,504.3 | | | | 362.1 | | | | 14 | % | | | 2,806.3 | | | | 2,426.9 | | | | 379.4 | | | | 16 | % | | Permian Delaware | | 2,805.1 | | | | 2,560.8 | | | | 244.3 | | | | 10 | % | | | 2,727.0 | | | | 2,528.1 | | | | 198.9 | | | | 8 | % | | Total Permian | | 5,671.5 | | | | 5,065.1 | | | | 606.4 | | | | 12 | % | | | 5,533.3 | | | | 4,955.0 | | | | 578.3 | | | | 12 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX (5) | | 339.4 | | | | 371.0 | | | | (31.6 | ) | | | (9 | %) | | | 322.2 | | | | 363.5 | | | | (41.3 | ) | | | (11 | %) | | North Texas | | 191.8 | | | | 208.0 | | | | (16.2 | ) | | | (8 | %) | | | 188.1 | | | | 201.8 | | | | (13.7 | ) | | | (7 | %) | | SouthOK (5) | | 361.5 | | | | 395.0 | | | | (33.5 | ) | | | (8 | %) | | | 359.3 | | | | 389.5 | | | | (30.2 | ) | | | (8 | %) | | WestOK | | 215.1 | | | | 211.0 | | | | 4.1 | | | | 2 | % | | | 212.6 | | | | 207.6 | | | | 5.0 | | | | 2 | % | | Total Central | | 1,107.8 | | | | 1,185.0 | | | | (77.2 | ) | | | (7 | %) | | | 1,082.2 | | | | 1,162.4 | | | | (80.2 | ) | | | (7 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | 143.9 | | | | 128.9 | | | | 15.0 | | | | 12 | % | | | 135.5 | | | | 130.3 | | | | 5.2 | | | | 4 | % | | Total Field | | 6,923.2 | | | | 6,379.0 | | | | 544.2 | | | | 9 | % | | | 6,751.0 | | | | 6,247.7 | | | | 503.3 | | | | 8 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 467.0 | | | | 552.1 | | | | (85.1 | ) | | | (15 | %) | | | 495.8 | | | | 530.7 | | | | (34.9 | ) | | | (7 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 7,390.2 | | | | 6,931.1 | | | | 459.1 | | | | 7 | % | | | 7,246.8 | | | | 6,778.4 | | | | 468.4 | | | | 7 | % | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | 424.1 | | | | 363.6 | | | | 60.5 | | | | 17 | % | | | 408.4 | | | | 349.4 | | | | 59.0 | | | | 17 | % | | Permian Delaware | | 364.5 | | | | 332.5 | | | | 32.0 | | | | 10 | % | | | 335.7 | | | | 326.7 | | | | 9.0 | | | | 3 | % | | Total Permian | | 788.6 | | | | 696.1 | | | | 92.5 | | | | 13 | % | | | 744.1 | | | | 676.1 | | | | 68.0 | | | | 10 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | SouthTX (5) | | 42.2 | | | | 45.6 | | | | (3.4 | ) | | | (7 | %) | | | 35.6 | | | | 42.0 | | | | (6.4 | ) | | | (15 | %) | | North Texas | | 23.5 | | | | 24.3 | | | | (0.8 | ) | | | (3 | %) | | | 22.7 | | | | 23.7 | | | | (1.0 | ) | | | (4 | %) | | SouthOK (5) | | 43.5 | | | | 47.3 | | | | (3.8 | ) | | | (8 | %) | | | 35.8 | | | | 43.1 | | | | (7.3 | ) | | | (17 | %) | | WestOK | | 15.5 | | | | 12.5 | | | | 3.0 | | | | 24 | % | | | 13.6 | | | | 12.8 | | | | 0.8 | | | | 6 | % | | Total Central | | 124.7 | | | | 129.7 | | | | (5.0 | ) | | | (4 | %) | | | 107.7 | | | | 121.6 | | | | (13.9 | ) | | | (11 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | 18.0 | | | | 15.6 | | | | 2.4 | | | | 15 | % | | | 16.3 | | | | 15.5 | | | | 0.8 | | | | 5 | % | | Total Field | | 931.3 | | | | 841.4 | | | | 89.9 | | | | 11 | % | | | 868.1 | | | | 813.2 | | | | 54.9 | | | | 7 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | 34.4 | | | | 36.8 | | | | (2.4 | ) | | | (7 | %) | | | 36.7 | | | | 36.5 | | | | 0.2 | | | | 1 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | 965.7 | | | | 878.2 | | | | 87.5 | | | | 10 | % | | | 904.8 | | | | 849.7 | | | | 55.1 | | | | 6 | % | | Crude oil, Badlands, MBbl/d | | 99.1 | | | | 104.7 | | | | (5.6 | ) | | | (5 | %) | | | 96.8 | | | | 107.7 | | | | (10.9 | ) | | | (10 | %) | | Crude oil, Permian, MBbl/d | | 27.9 | | | | 29.4 | | | | (1.5 | ) | | | (5 | %) | | | 27.7 | | | | 27.5 | | | | 0.2 | | | | 1 | % | | Natural gas sales, BBtu/d (3) | | 2,876.8 | | | | 2,672.6 | | | | 204.2 | | | | 8 | % | | | 2,763.7 | | | | 2,622.8 | | | | 140.9 | | | | 5 | % | | NGL sales, MBbl/d (3) | | 569.7 | | | | 493.8 | | | | 75.9 | | | | 15 | % | | | 534.3 | | | | 476.6 | | | | 57.7 | | | | 12 | % | | Condensate sales, MBbl/d | | 21.2 | | | | 19.4 | | | | 1.8 | | | | 9 | % | | | 20.1 | | | | 19.6 | | | | 0.5 | | | | 3 | % | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | 0.10 | | | | 1.29 | | | | (1.19 | ) | | | (92 | %) | | | 0.77 | | | | 1.94 | | | | (1.17 | ) | | | (60 | %) | | NGL, $/gal | | 0.44 | | | | 0.41 | | | | 0.03 | | | | 7 | % | | | 0.46 | | | | 0.47 | | | | (0.01 | ) | | | (2 | %) | | Condensate, $/Bbl | | 72.83 | | | | 85.79 | | | | (12.96 | ) | | | (15 | %) | | | 74.91 | | | | 76.02 | | | | (1.11 | ) | | | (1 | %) |