Targa Resources Corp. Reports Record Second Quarter 2024 Results and Increases Full Year 2024 Outlook
Second quarter 2024 net income attributable to
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
Targa repurchased 2,985,816 shares of its common stock during the second quarter of 2024 at a weighted average per share price of
Second Quarter 2024 -
Targa reported record second quarter adjusted EBITDA of
Capitalization and Liquidity
The Company’s total consolidated debt as of
Total consolidated liquidity as of
Financing Update
On
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
In
On
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
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
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
| (1) | Adjusted EBITDA is a non-GAAP financial measure and is discussed under “Non-GAAP Financial Measures.” |
| Three Months Ended |
Six Months Ended |
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| 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 |
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
The increase in commodity sales reflects higher NGL prices (
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
The increase in commodity sales reflects higher NGL, natural gas and condensate volumes (
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 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 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
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended |
Six Months Ended |
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| 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 |
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 | %) | |||||||||||||||||||
| 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 |
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 | %) | |||||||||||||||||||
| 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 | %) | |||||||||||||||||||
________________________
| (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 |
Three Months Ended |
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| (In millions, except volumetric data and price amounts) | |||||||||||||||||||||||
| Volume Settled |
Price Spread (1) |
Gain (Loss) |
Volume Settled |
Price Spread (1) |
Gain (Loss) |
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| Natural gas (BBtu) | 10.5 | $ | 2.58 | $ | 27.1 | 15.3 | $ | 1.73 | $ | 26.4 | |||||||||||||
| NGL (MMgal) | 112.0 | 0.05 | 5.1 | 164.9 | 0.11 | 17.7 | |||||||||||||||||
| Crude oil (MBbl) | 0.4 | (11.25 | ) | (4.5 | ) | 0.6 | (3.67 | ) | (2.2 | ) | |||||||||||||
| $ | 27.7 | $ | 41.9 | ||||||||||||||||||||
| Six Months Ended |
Six Months Ended |
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| (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) | 26.2 | $ | 1.73 | $ | 45.4 | 35.0 | $ | 1.51 | $ | 52.9 | |||||||||||||
| NGL (MMgal) | 246.1 | 0.03 | 6.8 | 349.0 | 0.08 | 27.2 | |||||||||||||||||
| Crude oil (MBbl) | 0.9 | (8.22 | ) | (7.4 | ) | 1.2 | (4.17 | ) | (5.0 | ) | |||||||||||||
| $ | 44.8 | $ | 75.1 | ||||||||||||||||||||
________________________
| (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
The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees in the Permian, 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 Midway plant during the second quarter of 2023, the Greenwood and Wildcat II plants during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, and continued strong producer activity.
The increase in operating expenses was primarily due to higher volumes in the Permian and the addition of the Midway, Greenwood, Wildcat II and Roadrunner II plants.
Six Months Ended
The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian 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 and Wildcat II plants during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, and continued strong producer activity.
The increase in operating expenses was primarily due to higher volumes in the Permian and the addition of the Legacy II, Midway, Greenwood, Wildcat II and Roadrunner II plants.
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
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended |
Six Months Ended |
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| 2024 | 2023 | 2024 vs. 2023 | 2024 | 2023 | 2024 vs. 2023 | ||||||||||||||||||||||||||
| (In millions, except operating statistics) | |||||||||||||||||||||||||||||||
| Operating margin | $ | 547.7 | $ | 408.0 | $ | 139.7 | 34 | % | $ | 1,079.8 | $ | 937.1 | $ | 142.7 | 15 | % | |||||||||||||||
| Operating expenses | 85.4 | 82.5 | 2.9 | 4 | % | 175.4 | 159.0 | 16.4 | 10 | % | |||||||||||||||||||||
| Adjusted operating margin | $ | 633.1 | $ | 490.5 | $ | 142.6 | 29 | % | $ | 1,255.2 | $ | 1,096.1 | $ | 159.1 | 15 | % | |||||||||||||||
| Operating statistics MBbl/d (1): | |||||||||||||||||||||||||||||||
| NGL pipeline transportation volumes (2) | 783.5 | 620.7 | 162.8 | 26 | % | 750.6 | 579.0 | 171.6 | 30 | % | |||||||||||||||||||||
| Fractionation volumes | 902.2 | 794.4 | 107.8 | 14 | % | 849.7 | 776.7 | 73.0 | 9 | % | |||||||||||||||||||||
| Export volumes (3) | 394.1 | 303.2 | 90.9 | 30 | % | 416.6 | 338.1 | 78.5 | 23 | % | |||||||||||||||||||||
| NGL sales | 1,018.4 | 947.0 | 71.4 | 8 | % | 1,123.0 | 977.1 | 145.9 | 15 | % | |||||||||||||||||||||
________________________
| (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 |
Three Months Ended
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 and the addition of Train 9 during the second quarter of 2024. Marketing margin increased due to greater optimization opportunities. LPG export margin increased due to higher volumes as the Company benefited from the completion of its export expansion 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, and the addition of Train 9, partially offset by lower repairs and maintenance.
Six Months Ended
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems and the addition of Train 9 during the second quarter of 2024. LPG export margin increased due to higher volumes as the Company benefited from the completion of its export expansion during the third quarter of 2023 and the Houston Ship Channel allowing night-time vessel transits, partially offset by maintenance and required inspections. Greater seasonal optimization opportunities drove marketing margin higher during the first quarter of 2023.
The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher repairs and maintenance, and the addition of Train 9.
Other
| Three Months Ended |
Six Months Ended |
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| 2024 | 2023 | 2024 vs. 2023 | 2024 | 2023 | 2024 vs. 2023 | ||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating margin | $ | (46.6 | ) | $ | 151.9 | $ | (198.5 | ) | $ | (68.7 | ) | $ | 327.7 | $ | (396.4 | ) | |||||||
| Adjusted operating margin | $ | (46.6 | ) | $ | 151.9 | $ | (198.5 | ) | $ | (68.7 | ) | $ | 327.7 | $ | (396.4 | ) | |||||||
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 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
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
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 tax (expense) benefit. 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 presents a reconciliation of Net income (loss) attributable to
| Three Months Ended |
Six Months Ended |
||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||
| (In millions) | |||||||||||||||
| Reconciliation of Net income (loss) attributable to |
|||||||||||||||
| Net income (loss) attributable to |
$ | 298.5 | $ | 329.3 | $ | 573.7 | $ | 826.3 | |||||||
| Interest (income) expense, net | 176.0 | 166.6 | 404.6 | 334.7 | |||||||||||
| Income tax expense (benefit) | 94.3 | 96.4 | 177.1 | 206.7 | |||||||||||
| Depreciation and amortization expense | 348.6 | 332.1 | 689.1 | 656.9 | |||||||||||
| (Gain) loss on sale or disposition of assets | (0.6 | ) | (1.7 | ) | (1.6 | ) | (3.2 | ) | |||||||
| Write-down of assets | 0.3 | 1.7 | 1.2 | 2.6 | |||||||||||
| (Gain) loss from financing activities | 0.8 | — | 0.8 | — | |||||||||||
| Equity (earnings) loss | (2.9 | ) | (3.4 | ) | (5.6 | ) | (3.2 | ) | |||||||
| Distributions from unconsolidated affiliates | 5.9 | 6.2 | 12.2 | 8.8 | |||||||||||
| Compensation on equity grants | 15.1 | 15.0 | 29.7 | 30.0 | |||||||||||
| Risk management activities | 46.6 | (151.9 | ) | 68.8 | (327.7 | ) | |||||||||
| Noncontrolling interests adjustments (1) | 1.7 | (1.2 | ) | 0.8 | (2.2 | ) | |||||||||
| Adjusted EBITDA | $ | 984.3 | $ | 789.1 | $ | 1,950.8 | $ | 1,729.7 | |||||||
| Interest expense on debt obligations (2) | (172.4 | ) | (163.6 | ) | (397.3 | ) | (328.8 | ) | |||||||
| Cash taxes | (3.4 | ) | (3.5 | ) | (6.3 | ) | (7.7 | ) | |||||||
| Adjusted Cash Flow from Operations | $ | 808.5 | $ | 622.0 | $ | 1,547.2 | $ | 1,393.2 | |||||||
| Maintenance capital expenditures, net (3) | (52.8 | ) | (46.2 | ) | (102.7 | ) | (88.0 | ) | |||||||
| Growth capital expenditures, net (3) | (798.7 | ) | (579.5 | ) | (1,484.5 | ) | (994.9 | ) | |||||||
| Adjusted Free Cash Flow | $ | (43.0 | ) | $ | (3.7 | ) | $ | (40.0 | ) | $ | 310.3 | ||||
________________________
| (1) | Noncontrolling interest portion of depreciation and amortization expense. |
| (2) | Excludes amortization of interest expense. The three and six months ended |
| (3) | 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 2024:
| 2024E | |||
| (In millions) | |||
| Reconciliation of Estimated Net Income Attributable to |
|||
| Estimated Adjusted EBITDA | |||
| Net income attributable to |
$ | 1,355.0 | |
| Interest expense, net (1) | 790.0 | ||
| Income tax expense | 360.0 | ||
| Depreciation and amortization expense | 1,355.0 | ||
| Equity earnings | (15.0 | ) | |
| Distributions from unconsolidated affiliates | 25.0 | ||
| Compensation on equity grants | 65.0 | ||
| Risk management and other | 70.0 | ||
| Noncontrolling interests adjustments (2) | (5.0 | ) | |
| Estimated Adjusted EBITDA | $ | 4,000.0 | |
________________________
| (1) | Includes |
| (2) | Noncontrolling interest portion of depreciation and amortization expense. |
Regulation FD Disclosures
The Company uses any of the following to comply with its disclosure obligations under Regulation FD: press releases,
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
Contact the Company’s investor relations department by email at InvestorRelations@targaresources.com or by phone at (713) 584-1133.
Vice President, Finance & Investor Relations
President – Finance and Administration
Source: Targa Resources Corp.