Targa Resources Corp. press release
Targa Resources Corp. Reports Record Third Quarter 2025 Results and Announces Expectation for a 25% Increase to its 2026 Common Dividend
NYSE - New York Stock Exchange · Natural Gas · Natural Gas Liquids · Oil · United States
HOUSTON, Nov. 05, 2025 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported third quarter 2025 results.
Third quarter 2025 net income attributable to Targa Resources Corp. was $478.4 million compared to $387.4 million for the third quarter of 2024. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) ( 1) of $1,274.8 million for the third quarter of 2025 compared to $1,069.7 million for the third quarter of 2024.
Highlights
Record adjusted EBITDA for the third quarter of $1.3 billion, a 19% increase year over year and a 10% increase compared to the second quarter Record Permian, NGL transportation, and fractionation volumes during the third quarter Repurchased approximately $156 million of common stock during the third quarter, and $605 million for the nine months ended September 30, 2025 Estimate full year 2025 adjusted EBITDA to be around the top end of $4.65 billion to $4.85 billion range In October, commenced operations at its new 275 million cubic feet per day (“MMcf/d”) Bull Moose II plant in the Permian Delaware In September, announced plans to construct the Speedway NGL Pipeline, the Yeti plant in Permian Delaware, and Buffalo Run, an expansion of Targa’s intrastate natural gas pipeline system in the Permian Announced today plans to construct a new 275 MMcf/d gas plant in the Permian Delaware in New Mexico Moving forward with its 36-mile Forza interstate natural gas pipeline in the Permian Delaware Expect to recommend to Targa’s Board of Directors an annual common dividend per share of $5.00 in 2026, a 25% increase to 2025
On October 16, 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 third quarter of 2025. Total cash dividends of approximately $215 million will be paid on November 17, 2025 on all outstanding shares of common stock to holders of record as of the close of business on October 31, 2025.
During the third quarter of 2025, Targa repurchased 932,023 shares of its common stock at a weighted average per share price of $166.95 for a total net cost of $155.6 million. As of September 30, 2025, there was $1,410.6 million remaining under the Company’s Share Repurchase Programs.
Third Quarter 2025 - Sequential Quarter over Quarter Commentary
Targa reported record third quarter adjusted EBITDA of $1,274.8 million, representing a 10 percent increase compared to the second quarter of 2025. 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 the in-service of its Pembrook II plant in Permian Midland during the third quarter. In the L&T segment, record NGL pipeline transportation and fractionation volumes and higher marketing margin drove the sequential increase in segment adjusted operating margin. Increased NGL pipeline transportation and fractionation volumes were predominantly attributable to higher supply volumes from Targa’s Permian G&P systems and the completion of a planned turnaround at a portion of Targa’s fractionation facilities in Mont Belvieu, Texas during the second quarter. Marketing margin increased due to greater optimization opportunities.
Capitalization, Financing and Liquidity
The Company’s total consolidated debt as of September 30, 2025 was $17,431.3 million, net of $112.5 million of debt issuance costs and $37.4 million of unamortized discount, with $15,329.2 million of outstanding senior unsecured notes, $1,295.0 million outstanding under the Commercial Paper Program, $600.0 million outstanding under the Securitization Facility, and $357.0 million of finance lease liabilities.
Total consolidated liquidity as of September 30, 2025 was approximately $2.3 billion, including $2.2 billion available under the TRGP Revolver and $124.1 million of cash.
Growth Projects Update
In Targa’s G&P segment, the Company commenced operations of its new 275 MMcf/d Bull Moose II plant in the Permian Delaware in October 2025. Construction continues on Targa’s 275 MMcf/d East Pembrook and East Driver plants in Permian Midland, and its 275 MMcf/d Falcon II plant in Permian Delaware. In September 2025, Targa announced plans to construct a new 275 MMcf/d gas processing plant in the Permian Delaware (the “Yeti plant”). The Yeti plant is expected to begin operations in the third quarter of 2027.
In November 2025, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced the construction of a new 275 MMcf/d natural gas processing plant (the “Copperhead plant”) in the Permian Delaware in New Mexico. The Copperhead plant is expected to begin operations in the first quarter of 2027.
In Targa’s L&T segment, construction continues on the Company’s Delaware Express Pipeline expansion, its 150 MBbl/d Train 11 and Train 12 fractionators in Mont Belvieu, its GPMT LPG Export Expansion, and its Bull Run Extension.
In September 2025, Targa announced plans to construct the Speedway NGL Pipeline (“Speedway”). Speedway will transport NGLs from Targa’s existing assets and future plant additions in the Permian Basin to Targa’s fractionation and storage complex in Mont Belvieu. Speedway is expected to begin operations in the third quarter of 2027. Targa also announced plans to construct Buffalo Run, a new 35-mile natural gas pipeline that will enhance connectivity across several Targa plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service. Buffalo Run is expected to be completed in stages and fully complete in early 2028.
In November 2025, following the completion of its open season, Targa announced the Company is moving forward with a new 36-mile intra-basin natural gas pipeline in the Permian Delaware (“Forza”) to enhance connectivity to the Waha hub. Forza is expected to begin operations in mid-2028, pending receipt of necessary regulatory approvals.
2025 Outlook and Capital Allocation Update
Targa now estimates full year adjusted EBITDA for 2025 to be around the top end of its $4.65 billion to $4.85 billion range. The Company’s estimate for 2025 net growth capital expenditures is approximately $3.3 billion, and its estimate for 2025 net maintenance capital expenditures remains unchanged at approximately $250 million.
For the first quarter of 2026, Management intends to recommend to Targa’s Board of Directors an increase to its common dividend to $1.25 per common share or $5.00 per common share annualized. The recommended common dividend per share increase, if approved, would be effective for the first quarter of 2026 and payable in May 2026. Beyond 2026, Targa expects to be in position to continue to provide meaningful annual increases to its common dividend.
For the nine months ended September 30, 2025, Targa has repurchased 3,538,285 shares of common stock at a weighted average per share price of $170.93 for a total net cost of $604.8 million. The Company expects to continue to be in position to opportunistically repurchase its common stock going forward with approximately $1.4 billion remaining under its common Share Repurchase Programs as of September 30, 2025.
The Company is currently in its planning process, and consistent with previous years, Targa plans to detail its full year 2026 operational and financial outlook in February 2026 in conjunction with its fourth quarter 2025 earnings announcement.
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 November 5, 2025 to discuss its third 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/ib9g4uey . 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, | | | | | | | | | | | | | | | | | | | | | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | | | | | | | | | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of commodities | $ | 3,469.9 | | | $ | 3,217.0 | | | $ | 252.9 | | | | 8 | % | | $ | 10,990.6 | | | $ | 10,126.2 | | | $ | 864.4 | | | 9 | % | | Fees from midstream services | | 681.3 | | | | 634.8 | | | | 46.5 | | | | 7 | % | | | 1,982.2 | | | | 1,850.0 | | | | 132.2 | | | 7 | % | | Total revenues | | 4,151.2 | | | | 3,851.8 | | | | 299.4 | | | | 8 | % | | | 12,972.8 | | | | 11,976.2 | | | | 996.6 | | | 8 | % | | Product purchases and fuel | | 2,506.4 | | | | 2,365.0 | | | | 141.4 | | | | 6 | % | | | 8,200.2 | | | | 7,780.4 | | | | 419.8 | | | 5 | % | | Operating expenses | | 333.5 | | | | 301.0 | | | | 32.5 | | | | 11 | % | | | 960.7 | | | | 869.7 | | | | 91.0 | | | 10 | % | | Depreciation and amortization expense | | 383.5 | | | | 355.4 | | | | 28.1 | | | | 8 | % | | | 1,124.8 | | | | 1,044.5 | | | | 80.3 | | | 8 | % | | General and administrative expense | | 104.8 | | | | 102.6 | | | | 2.2 | | | | 2 | % | | | 294.3 | | | | 287.4 | | | | 6.9 | | | 2 | % | | Other operating (income) expense | | (13.9 | ) | | | (0.4 | ) | | | (13.5 | ) | | NM | | | | (21.0 | ) | | | (0.7 | ) | | | (20.3 | ) | NM | | | | | Income (loss) from operations | | 836.9 | | | | 728.2 | | | | 108.7 | | | | 15 | % | | | 2,413.8 | | | | 1,994.9 | | | | 418.9 | | | 21 | % | | Interest expense, net | | (221.3 | ) | | | (184.9 | ) | | | (36.4 | ) | | | 20 | % | | | (636.8 | ) | | | (589.5 | ) | | | (47.3 | ) | | 8 | % | | Equity earnings (loss) | | 6.4 | | | | 2.2 | | | | 4.2 | | | | 191 | % | | | 17.0 | | | | 7.9 | | | | 9.1 | | | 115 | % | | Other, net | | (1.1 | ) | | | (0.4 | ) | | | (0.7 | ) | | NM | | | | 0.2 | | | | 0.3 | | | | (0.1 | ) | NM | | | | | Income tax (expense) benefit | | (134.3 | ) | | | (97.0 | ) | | | (37.3 | ) | | | 38 | % | | | (390.6 | ) | | | (274.1 | ) | | | (116.5 | ) | | 43 | % | | Net income (loss) | | 486.6 | | | | 448.1 | | | | 38.5 | | | | 9 | % | | | 1,403.6 | | | | 1,139.5 | | | | 264.1 | | | 23 | % | | Less: Net income (loss) attributable to noncontrolling interests | | 8.2 | | | | 60.7 | | | | (52.5 | ) | | | (86 | %) | | | 25.6 | | | | 178.5 | | | | (152.9 | ) | | (86 | %) | | Net income (loss) attributable to Targa Resources Corp. | | 478.4 | | | | 387.4 | | | | 91.0 | | | | 23 | % | | | 1,378.0 | | | | 961.0 | | | | 417.0 | | | 43 | % | | Premium on repurchase of noncontrolling interests, net of tax | | — | | | | — | | | | — | | | | — | | | | 70.5 | | | | — | | | | 70.5 | | | 100 | % | | Net income (loss) attributable to common shareholders | $ | 478.4 | | | $ | 387.4 | | | $ | 91.0 | | | | 23 | % | | $ | 1,307.5 | | | $ | 961.0 | | | $ | 346.5 | | | 36 | % | | Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA (1) | $ | 1,274.8 | | | $ | 1,069.7 | | | $ | 205.1 | | | | 19 | % | | $ | 3,616.3 | | | $ | 3,020.3 | | | $ | 596.0 | | | 20 | % | | Adjusted cash flow from operations (1) | | 1,082.8 | | | | 884.6 | | | | 198.2 | | | | 22 | % | | | 2,987.2 | | | | 2,431.7 | | | | 555.5 | | | 23 | % | | Adjusted free cash flow (1) | | 172.8 | | | | 124.2 | | | | 48.6 | | | | 39 | % | | | 491.4 | | | | 84.2 | | | | 407.2 | | 484 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (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, 2025 Compared to Three Months Ended September 30, 2024
The increase in commodity sales reflected higher natural gas prices ($322.3 million) and higher NGL volumes ($213.8 million), partially offset by lower NGL prices ($263.3 million) and the unfavorable impact of hedges ($16.6 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 natural gas prices and higher NGL volumes, partially offset by lower NGL prices.
The increase in operating expenses was primarily due to higher maintenance, taxes and labor costs as a result of system expansions.
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 other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through the Company’s carbon capture and sequestration activities.
The increase in interest expense, net, was primarily due to higher borrowings in 2025.
The increase in income tax (expense) benefit 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”).
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024
The increase in commodity sales reflected higher natural gas prices ($815.5 million), higher NGL volumes ($354.1 million) and the favorable impact of hedges ($17.8 million), partially offset by lower NGL and condensate prices ($318.1 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 predominantly due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
The increase in product purchases and fuel reflected higher natural gas prices and higher NGL volumes, partially offset by lower NGL prices.
The increase in operating expenses was primarily due to higher maintenance and labor costs and taxes as a result of system expansions and the planned turnaround at a portion of our 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 other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through the Company’s carbon capture and sequestration activities.
The increase in interest expense, net, was primarily due to higher borrowings in 2025, partially offset by the recognition of cumulative interest on a 2024 legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp (the “Splitter Agreement”).
The increase in income tax (expense) benefit 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 September 30, | | | | | | | | | | Nine Months Ended September 30, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | 2025 | | | 2024 | | | 2025 vs. 2024 | | | | | | | | | | | | | | | | | | | | | | | | | (In millions, except operating statistics and price amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating margin | $ | | 637.6 | | | $ | | 584.3 | | | $ | | 53.3 | | | | 9 | % | | $ | | 1,827.4 | | | $ | | 1,713.4 | | | $ | | 114.0 | | | | 7 | % | | Operating expenses | | | 236.1 | | | | | 203.7 | | | | | 32.4 | | | | 16 | % | | | | 663.7 | | | | | 597.2 | | | | | 66.5 | | | | 11 | % | | Adjusted operating margin | $ | | 873.7 | | | $ | | 788.0 | | | $ | | 85.7 | | | | 11 | % | | $ | | 2,491.1 | | | $ | | 2,310.6 | | | $ | | 180.5 | | | | 8 | % | | Operating statistics (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plant natural gas inlet, MMcf/d (2) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 3,246.0 | | | | | 3,044.2 | | | | | 201.8 | | | | 7 | % | | | | 3,113.5 | | | | | 2,886.1 | | | | | 227.4 | | | | 8 | % | | Permian Delaware | | | 3,375.6 | | | | | 2,900.2 | | | | | 475.4 | | | | 16 | % | | | | 3,190.6 | | | | | 2,785.2 | | | | | 405.4 | | | | 15 | % | | Total Permian | | | 6,621.6 | | | | | 5,944.4 | | | | | 677.2 | | | | 11 | % | | | | 6,304.1 | | | | | 5,671.3 | | | | | 632.8 | | | | 11 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | | 1,071.0 | | | | | 1,078.1 | | | | | (7.1 | ) | | | (1 | %) | | | | 1,047.6 | | | | | 1,080.9 | | | | | (33.3 | ) | | | (3 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) (6) | | | 129.9 | | | | | 145.4 | | | | | (15.5 | ) | | | (11 | %) | | | | 132.5 | | | | | 138.8 | | | | | (6.3 | ) | | | (5 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 445.9 | | | | | 402.1 | | | | | 43.8 | | | | 11 | % | | | | 414.6 | | | | | 464.3 | | | | | (49.7 | ) | | | (11 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 8,268.4 | | | | | 7,570.0 | | | | | 698.4 | | | | 9 | % | | | | 7,898.8 | | | | | 7,355.3 | | | | | 543.5 | | | | 7 | % | | NGL production, MBbl/d (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Permian Midland (4) | | | 478.3 | | | | | 450.6 | | | | | 27.7 | | | | 6 | % | | | | 452.8 | | | | | 422.6 | | | | | 30.2 | | | | 7 | % | | Permian Delaware | | | 452.2 | | | | | 377.4 | | | | | 74.8 | | | | 20 | % | | | | 408.8 | | | | | 349.7 | | | | | 59.1 | | | | 17 | % | | Total Permian | | | 930.5 | | | | | 828.0 | | | | | 102.5 | | | | 12 | % | | | | 861.6 | | | | | 772.3 | | | | | 89.3 | | | | 12 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Central (5) | | | 111.1 | | | | | 98.0 | | | | | 13.1 | | | | 13 | % | | | | 109.7 | | | | | 104.4 | | | | | 5.3 | | | | 5 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Badlands (5) | | | 16.6 | | | | | 18.3 | | | | | (1.7 | ) | | | (9 | %) | | | | 16.5 | | | | | 17.0 | | | | | (0.5 | ) | | | (3 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coastal | | | 36.9 | | | | | 33.9 | | | | | 3.0 | | | | 9 | % | | | | 33.8 | | | | | 35.8 | | | | | (2.0 | ) | | | (6 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 1,095.1 | | | | | 978.2 | | | | | 116.9 | | | | 12 | % | | | | 1,021.6 | | | | | 929.5 | | | | | 92.1 | | | | 10 | % | | Crude oil, Badlands, MBbl/d | | | 84.6 | | | | | 122.4 | | | | | (37.8 | ) | | | (31 | %) | | | | 93.9 | | | | | 105.4 | | | | | (11.5 | ) | | | (11 | %) | | Crude oil, Permian, MBbl/d | | | 25.2 | | | | | 26.7 | | | | | (1.5 | ) | | | (6 | %) | | | | 26.8 | | | | | 27.4 | | | | | (0.6 | ) | | | (2 | %) | | Natural gas sales, BBtu/d (3) | | | 2,930.8 | | | | | 2,842.9 | | | | | 87.9 | | | | 3 | % | | | | 2,782.3 | | | | | 2,779.2 | | | | | 3.1 | | | | — | | | NGL sales, MBbl/d (3) | | | 634.8 | | | | | 581.5 | | | | | 53.3 | | | | 9 | % | | | | 604.1 | | | | | 550.1 | | | | | 54.0 | | | | 10 | % | | Condensate sales, MBbl/d | | | 18.0 | | | | | 17.3 | | | | | 0.7 | | | | 4 | % | | | | 18.7 | | | | | 19.2 | | | | | (0.5 | ) | | | (3 | %) | | Average realized prices (7): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural gas, $/MMBtu | | | 1.20 | | | | | 0.09 | | | | | 1.11 | | | NM | | | | | 1.45 | | | | | 0.54 | | | | | 0.91 | | | | 169 | % | | | NGL, $/gal | | | 0.39 | | | | | 0.44 | | | | | (0.05 | ) | | | (11 | %) | | | | 0.43 | | | | | 0.45 | | | | | (0.02 | ) | | | (4 | %) | | Condensate, $/Bbl | | | 67.75 | | | | | 77.20 | | | | | (9.45 | ) | | | (12 | %) | | | | 67.78 | | | | | 75.60 | | | | | (7.82 | ) | | | (10 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |