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 | %) | ||||||||||||||||||||
| (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, other than Badlands. |
| (3) | Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes. |
| (4) | Permian Midland includes operations in WestTX, of which the Company owns a 72.8% undivided interest, and other plants that are owned 100% by the Company. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials. |
| (5) | Operations include facilities that are not wholly owned by the Company. |
| (6) | Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant. |
| (7) | Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to the Company’s equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees. |
The following table presents the realized commodity hedge gain (loss) attributable to the Company’s equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:
| Three Months Ended December 31, 2024 | Three Months Ended December 31, 2023 | |||||||||||||||||||||||
| (In millions, except volumetric data and price amounts) | ||||||||||||||||||||||||
|
Volume Settled |
Price Spread (1) |
Gain (Loss) |
Volume Settled |
Price Spread (1) |
Gain (Loss) |
|||||||||||||||||||
| Natural gas (BBtu) | 8.1 | $ | 1.84 | $ | 14.9 | 13.2 | $ | 1.15 | $ | 15.2 | ||||||||||||||
| NGL (MMgal) | 101.0 | 0.01 | 0.9 | 165.3 | 0.09 | 15.5 | ||||||||||||||||||
| Crude oil (MBbl) | 0.7 | 5.00 | 3.5 | 0.6 | (6.17 | ) | (3.7 | ) | ||||||||||||||||
| $ | 19.3 | $ | 27.0 | |||||||||||||||||||||
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||||
| (In millions, except volumetric data and price amounts) | ||||||||||||||||||||||||
|
Volume Settled |
Price Spread (1) |
Gain (Loss) |
Volume Settled |
Price Spread (1) |
Gain (Loss) |
|||||||||||||||||||
| Natural gas (BBtu) | 43.7 | $ | 1.92 | $ | 84.1 | 63.2 | $ | 1.22 | $ | 77.4 | ||||||||||||||
| NGL (MMgal) | 449.8 | 0.04 | 15.8 | 680.3 | 0.07 | 49.9 | ||||||||||||||||||
| Crude oil (MBbl) | 2.1 | (2.05 | ) | (4.3 | ) | 2.4 | (6.92 | ) | (16.6 | ) | ||||||||||||||
| $ | 95.6 | $ | 110.7 | |||||||||||||||||||||
| (1) | The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. |
Three Months Ended December 31, 2024 Compared to Three Months Ended December 31, 2023
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes which drove higher fee-based income in the Permian, and higher NGL Prices, partially offset by lower natural gas and condensate prices. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Wildcat II plant during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, and continued strong producer activity.
The increase in operating expenses was primarily due to higher volumes in the Permian and multiple plant additions in the Permian, partially offset by lower taxes in the Central region.
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes which drove higher fee-based income in the Permian, partially offset by lower natural gas and condensate prices. The increase in natural gas inlet volumes was attributable to the addition of the Legacy II plant during the first quarter of 2023, the Midway plant during the second quarter of 2023, the Greenwood I and Wildcat II plants during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, and continued strong producer activity.
The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.
Logistics and Transportation Segment
The Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of the Company’s other businesses. The Logistics and Transportation segment also includes Grand Prix NGL Pipeline, which connects the Company’s gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company’s Downstream facilities in Mont Belvieu, Texas. The Company’s Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||
| 2024 | 2023 | 2024 vs. 2023 | 2024 | 2023 | 2024 vs. 2023 | |||||||||||||||||||||||||||
| (In millions, except operating statistics) | ||||||||||||||||||||||||||||||||
| Operating margin | $ | 656.2 | $ | 554.2 | $ | 102.0 | 18 | % | $ | 2,355.1 | $ | 1,948.7 | $ | 406.4 | 21 | % | ||||||||||||||||
| Operating expenses | 88.7 | 84.4 | 4.3 | 5 | % | 362.3 | 332.0 | 30.3 | 9 | % | ||||||||||||||||||||||
| Adjusted operating margin | $ | 744.9 | $ | 638.6 | $ | 106.3 | 17 | % | $ | 2,717.4 | $ | 2,280.7 | $ | 436.7 | 19 | % | ||||||||||||||||
| Operating statistics MBbl/d (1): | ||||||||||||||||||||||||||||||||
| NGL pipeline transportation volumes (2) | 871.5 | 722.0 | 149.5 | 21 | % | 800.8 | 635.5 | 165.3 | 26 | % | ||||||||||||||||||||||
| Fractionation volumes | 1,089.5 | 844.8 | 244.7 | 29 | % | 936.1 | 798.1 | 138.0 | 17 | % | ||||||||||||||||||||||
| Export volumes (3) | 457.1 | 434.5 | 22.6 | 5 | % | 423.6 | 365.2 | 58.4 | 16 | % | ||||||||||||||||||||||
| NGL sales | 1,227.5 | 1,125.8 | 101.7 | 9 | % | 1,159.1 | 1,019.8 | 139.3 | 14 | % | ||||||||||||||||||||||
| (1) | Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. |
| (2) | Represents the total quantity of mixed NGLs that earn a transportation margin. |
| (3) | Export volumes represent the quantity of NGL products delivered to third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets. |
Three Months Ended December 31, 2024 Compared to Three Months Ended December 31, 2023
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin. LPG export margin was relatively flat. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems, the in-service of the Daytona NGL Pipeline during the third quarter of 2024, the addition of Train 9 during the second quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin increased due to greater optimization opportunities.
The increase in operating expenses was due to higher system volumes, higher taxes, higher compensation and benefits the in-service of the Daytona NGL Pipeline expansion during the third quarter of 2024, the addition of Train 9 during the second quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024, partially offset by lower repairs and maintenance.
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher marketing margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems, the addition of Train 9 during the second quarter of 2024, the in-service of the Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin increased due to greater optimization opportunities. LPG export margin increased due to higher volumes as Targa benefited from the completion of the export expansion project during the third quarter of 2023 and the Houston Ship Channel allowing night-time vessel transits, partially offset by maintenance and required inspections.
The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher taxes, higher repairs and maintenance and the addition of two trains during 2024.
Other
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2024 | 2023 | 2024 vs. 2023 | 2024 | 2023 | 2024 vs. 2023 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating margin | $ | (78.3 | ) | $ | (18.8 | ) | $ | (59.5 | ) | $ | (164.6 | ) | $ | 275.5 | $ | (440.1 | ) | |||||||
| Adjusted operating margin | $ | (78.3 | ) | $ | (18.8 | ) | $ | (59.5 | ) | $ | (164.6 | ) | $ | 275.5 | $ | (440.1 | ) | |||||||
Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s future commodity purchases and sales and natural gas transportation basis risk within the Company’s Logistics and Transportation segment.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent infrastructure companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary domestic infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company’s assets connect natural gas and NGLs to domestic and international markets with growing demand for cleaner fuels and feedstocks. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas; transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling, and purchasing and selling crude oil.
Targa is a FORTUNE 500 company and is included in the S&P 500.
For more information, please visit the Company’s website at www.targaresources.com.
Non-GAAP Financial Measures
This press release includes the Company’s non-GAAP financial measures: adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment). The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures.
The Company utilizes non-GAAP measures to analyze the Company’s performance. Adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within the Company’s industry, the Company’s definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of the Company’s non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes.
Adjusted Operating Margin
The Company defines adjusted operating margin for the Company’s segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.
Gathering and Processing adjusted operating margin consists primarily of:
- service fees related to natural gas and crude oil gathering, treating and processing; and
- revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and the Company’s equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
- service fees (including the pass-through of energy costs included in certain fee rates);
- system product gains and losses; and
- NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for the Company’s segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess:
- the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;
- the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
- the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for the Company’s segments monthly as a core internal management process. The Company believes that investors benefit from having access to the same financial measures that management uses in evaluating the Company’s operating results. The reconciliation of the Company’s adjusted operating margin to the most directly comparable GAAP measure is presented under “Review of Segment Performance.”
Adjusted EBITDA
The Company defines adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that the Company believes should be adjusted consistent with the Company’s core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the Company’s financial statements such as investors, commercial banks and others to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support the Company’s indebtedness and pay dividends to the Company’s investors.
Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
The Company defines adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash taxes. The Company defines adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures (net of any reimbursements of project costs) and growth capital expenditures, net of contributions from noncontrolling interest and contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations and adjusted free cash flow are performance measures used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
The following table reconciles the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated:
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2024 | 2023 | 2024 | 2023 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow | ||||||||||||||||
| Net income (loss) attributable to Targa Resources Corp. | $ | 351.0 | $ | 299.6 | $ | 1,312.0 | $ | 1,345.9 | ||||||||
| Interest (income) expense, net | 177.7 | 178.0 | 767.2 | 687.8 | ||||||||||||
| Income tax expense (benefit) | 110.5 | 102.5 | 384.5 | 363.2 | ||||||||||||
| Depreciation and amortization expense | 378.5 | 341.4 | 1,423.0 | 1,329.6 | ||||||||||||
| (Gain) loss on sale or disposition of assets | (0.4 | ) | (1.3 | ) | (3.1 | ) | (5.3 | ) | ||||||||
| Write-down of assets | 2.2 | 0.8 | 6.2 | 6.9 | ||||||||||||
| (Gain) loss from financing activities | — | 2.1 | 0.8 | 2.1 | ||||||||||||
| Equity (earnings) loss | (1.5 | ) | (2.8 | ) | (9.4 | ) | (9.0 | ) | ||||||||
| Distributions from unconsolidated affiliates | 8.7 | 4.5 | 25.3 | 18.6 | ||||||||||||
| Compensation on equity grants | 15.8 | 16.7 | 63.2 | 62.4 | ||||||||||||
| Risk management activities | 78.2 | 18.8 | 164.6 | (275.4 | ) | |||||||||||
| Noncontrolling interests adjustments (1) | 1.5 | (0.4 | ) | 3.9 | (3.7 | ) | ||||||||||
| Litigation expense (2) | — | — | 4.1 | 6.9 | ||||||||||||
| Adjusted EBITDA | $ | 1,122.2 | $ | 959.9 | $ | 4,142.3 | $ | 3,530.0 | ||||||||
| Interest expense on debt obligations (3) | (173.8 | ) | (174.9 | ) | (752.4 | ) | (675.8 | ) | ||||||||
| Cash taxes | (7.5 | ) | (4.9 | ) | (17.5 | ) | (13.6 | ) | ||||||||
| Adjusted Cash Flow from Operations | $ | 940.9 | $ | 780.1 | $ | 3,372.4 | $ | 2,840.6 | ||||||||
| Maintenance capital expenditures, net (4) | (65.0 | ) | (70.4 | ) | (231.9 | ) | (223.4 | ) | ||||||||
| Growth capital expenditures, net (4) | (819.7 | ) | (636.0 | ) | (3,000.4 | ) | (2,224.5 | ) | ||||||||
| Adjusted Free Cash Flow | $ | 56.2 | $ | 73.7 | $ | 140.1 | $ | 392.7 | ||||||||
| (1) | Represents adjustments related to the Company’s subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within Targa’s WestTX joint venture not subject to noncontrolling interest. |
| (2) | Litigation expense includes charges related to litigation resulting from the major winter storm in February 2021 that the Company considers outside the ordinary course of its business and/or not reflective of its ongoing core operations. The Company may incur such charges from time to time, and the Company believes it is useful to exclude such charges because it does not consider them reflective of its ongoing core operations and because of the generally singular nature of the claims underlying such litigation. |
| (3) | Excludes amortization of interest expense. The year ended December 31, 2024 includes $55.8 million of interest expense associated with the Splitter Agreement ruling. |
| (4) | Represents capital expenditures, net of contributions from noncontrolling interests and includes contributions to investments in unconsolidated affiliates. |
The following table presents a reconciliation of estimated net income of the Company to estimated adjusted EBITDA for 2025:
| 2025E | ||||
| (In millions) | ||||
| Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to | ||||
| Estimated Adjusted EBITDA | ||||
| Net income attributable to Targa Resources Corp. | $ | 1,765.0 | ||
| Interest expense, net | 875.0 | |||
| Income tax expense | 510.0 | |||
| Depreciation and amortization expense | 1,535.0 | |||
| Equity earnings | (20.0 | ) | ||
| Distributions from unconsolidated affiliates | 25.0 | |||
| Compensation on equity grants | 65.0 | |||
| Noncontrolling interests adjustments (1) | (5.0 | ) | ||
| Estimated Adjusted EBITDA | $ | 4,750.0 | ||
| (1) | Represents adjustments related to the Company’s subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within Targa’s WestTX joint venture not subject to noncontrolling interest. |
Regulation FD Disclosures
The Company uses any of the following to comply with its disclosure obligations under Regulation FD: press releases, SEC filings, public conference calls, or our website. The Company routinely posts important information on its website at www.targaresources.com, including information that may be deemed to be material. The Company encourages investors and others interested in the company to monitor these distribution channels for material disclosures.
Forward-Looking Statements
Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements, including statements regarding our projected financial performance, capital spending and payment of future dividends. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of our completion of capital projects and business development efforts, the expected growth of volumes on our systems, the impact of significant public health crises, commodity price volatility due to ongoing or new global conflicts, the impact of disruptions in the bank and capital markets, including those resulting from lack of access to liquidity for banking and financial services firms, and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its most recent Annual Report on Form 10-K, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Targa Investor Relations
[email protected]
(713) 584-1133
