Targa Resources Corp. Reports Record Fourth Quarter and Full Year 2023 Financial Results and Provides Outlook for 2024 and Positioning in 2025
Fourth quarter 2023 net income attributable to
Highlights
- Record full year adjusted EBITDA(1) for 2023 of
$3,530.0 million , a 22% increase over 2022 - Record full year 2023 Permian, NGL transportation, fractionation, and LPG export volumes
- Record full year 2023 common share repurchases of
$373.7 million - Exiting 2023 with ~90% of Gathering and Processing (“G&P”) volumes fee or fee-floor based
- Record quarterly adjusted EBITDA(1) for the fourth quarter of
$959.9 million , a 14% sequential increase - Record Permian, NGL transportation, fractionation, and LPG export volumes during the fourth quarter
- Completed its new 275 million cubic feet per day (“MMcf/d”) Wildcat II plant in Permian Delaware
- Estimate 2024 adjusted EBITDA between
$3.7 billion and$3.9 billion , an 8% increase over 2023 - Estimate 2024 net growth capital expenditures of
$2.3 billion to$2.5 billion - Continue to expect an annual common dividend per share of
$3.00 in 2024, a 50% increase to 2023 - Current estimate is
~$1.4 billion of net growth capital expenditures in 2025, which would drive a meaningful increase in adjusted free cash flow(1) in 2025
Targa’s record operational and financial results in 2023 despite a significantly lower commodity price environment demonstrates the resiliency of its diversified operations and growing fee based midstream businesses.
The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of
The Company reported distributable cash flow and adjusted free cash flow for the fourth quarter of 2023 of
On
Targa repurchased 475,040 shares of its common stock during the fourth quarter of 2023 at a weighted average per share price of
Fourth Quarter 2023 -
Targa reported fourth quarter adjusted EBITDA of
Capitalization and Liquidity
The Company’s total consolidated debt as of
Total consolidated liquidity as of
Financing Update
In
Growth Projects Update
Late in the fourth quarter, Targa commenced operations at its new 275 MMcf/d Wildcat II plant in Permian Delaware ahead of schedule and on-budget. Construction continues on its 275 MMcf/d Greenwood II plant in Permian Midland, and its 230 MMcf/d Roadrunner II and 275 MMcf/d
In response to increasing production and to meet the infrastructure needs of its customers, Targa has commenced spending on long-lead time items for its next gas plants in the
2024 Outlook and Capital Return Expectations
Targa’s 2024 operational and financial expectations assume Waha natural gas prices average
For 2024, Targa estimates full year adjusted EBITDA to be between
Targa’s estimate for 2024 net growth capital expenditures is between
For the first quarter of 2024, Targa intends to recommend to its Board of Directors an increase to its common dividend to
Positioning in 2025
For 2025, Targa estimates a meaningful step down in net growth capital expenditures versus 2023 and 2024 as the Company’s large downstream fractionation and NGL pipeline transportation expansions will be complete by the first quarter of 2025.
Assuming continued production growth in the
An earnings supplement presentation and an 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
(1) Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Non-GAAP Financial Measures.”
| Three Months Ended |
Year Ended |
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| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||||||||||
| Sales of commodities | $ | 3,647.9 | $ | 4,075.3 | $ | (427.4 | ) | (10 | %) | $ | 13,962.1 | $ | 19,066.0 | $ | (5,103.9 | ) | (27 | %) | |||||||||||||
| Fees from midstream services | 591.6 | 479.4 | 112.2 | 23 | % | 2,098.2 | 1,863.8 | 234.4 | 13 | % | |||||||||||||||||||||
| Total revenues | 4,239.5 | 4,554.7 | (315.2 | ) | (7 | %) | 16,060.3 | 20,929.8 | (4,869.5 | ) | (23 | %) | |||||||||||||||||||
| Product purchases and fuel | 2,898.5 | 3,324.2 | (425.7 | ) | (13 | %) | 10,676.4 | 16,882.1 | (6,205.7 | ) | (37 | %) | |||||||||||||||||||
| Operating expenses | 269.5 | 252.2 | 17.3 | 7 | % | 1,077.9 | 912.8 | 165.1 | 18 | % | |||||||||||||||||||||
| Depreciation and amortization expense | 341.4 | 329.8 | 11.6 | 4 | % | 1,329.6 | 1,096.0 | 233.6 | 21 | % | |||||||||||||||||||||
| General and administrative expense | 95.3 | 92.5 | 2.8 | 3 | % | 348.7 | 309.7 | 39.0 | 13 | % | |||||||||||||||||||||
| Other operating (income) expense | (0.5 | ) | 4.7 | (5.2 | ) | (111 | %) | 1.5 | 0.2 | 1.3 | NM | ||||||||||||||||||||
| Income (loss) from operations | 635.3 | 551.3 | 84.0 | 15 | % | 2,626.2 | 1,729.0 | 897.2 | 52 | % | |||||||||||||||||||||
| Interest expense, net | (178.0 | ) | (145.6 | ) | (32.4 | ) | 22 | % | (687.8 | ) | (446.1 | ) | (241.7 | ) | 54 | % | |||||||||||||||
| Equity earnings (loss) | 2.8 | 0.3 | 2.5 | NM | 9.0 | 9.1 | (0.1 | ) | (1 | %) | |||||||||||||||||||||
| Gain (loss) from financing activities | (2.1 | ) | — | (2.1 | ) | (100 | %) | (2.1 | ) | (49.6 | ) | 47.5 | 96 | % | |||||||||||||||||
| Gain (loss) from sale of equity method investment | — | — | — | — | — | 435.9 | (435.9 | ) | (100 | %) | |||||||||||||||||||||
| Other, net | 2.1 | (0.3 | ) | 2.4 | NM | (2.8 | ) | (15.1 | ) | 12.3 | 81 | % | |||||||||||||||||||
| Income tax (expense) benefit | (102.5 | ) | (9.8 | ) | (92.7 | ) | NM | (363.2 | ) | (131.8 | ) | (231.4 | ) | 176 | % | ||||||||||||||||
| Net income (loss) | 357.6 | 395.9 | (38.3 | ) | (10 | %) | 1,579.3 | 1,531.4 | 47.9 | 3 | % | ||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 58.0 | 77.9 | (19.9 | ) | (26 | %) | 233.4 | 335.9 | (102.5 | ) | (31 | %) | |||||||||||||||||||
| Net income (loss) attributable to |
299.6 | 318.0 | (18.4 | ) | (6 | %) | 1,345.9 | 1,195.5 | 150.4 | 13 | % | ||||||||||||||||||||
| Premium on repurchase of noncontrolling interests, net of tax | 19.4 | 0.1 | 19.3 | NM | 510.1 | 53.2 | 456.9 | NM | |||||||||||||||||||||||
| Dividends on Series A Preferred Stock | — | — | — | — | — | 30.0 | (30.0 | ) | (100 | %) | |||||||||||||||||||||
| Deemed dividends on Series A Preferred Stock | — | — | — | — | — | 215.5 | (215.5 | ) | (100 | %) | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 280.2 | $ | 317.9 | $ | (37.7 | ) | (12 | %) | $ | 835.8 | $ | 896.8 | $ | (61.0 | ) | (7 | %) | |||||||||||||
| Financial data: | |||||||||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 959.9 | $ | 840.4 | $ | 119.5 | 14 | % | $ | 3,530.0 | $ | 2,901.1 | $ | 628.9 | 22 | % | |||||||||||||||
| Distributable cash flow (1) | 709.7 | 655.5 | 54.2 | 8 | % | 2,617.2 | 2,278.7 | 338.5 | 15 | % | |||||||||||||||||||||
| Adjusted free cash flow (1) | 73.7 | 103.1 | (29.4 | ) | (29 | %) | 392.7 | 1,101.5 | (708.8 | ) | (64 | %) | |||||||||||||||||||
(1) Adjusted EBITDA, distributable cash flow 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 decrease in commodity sales reflects lower natural gas and NGL prices (
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, higher export volumes and higher terminaling and storage fees, partially offset by lower transportation and fractionation fees.
The decrease in product purchases and fuel reflects lower natural gas and NGL prices, partially offset by higher NGL and natural gas volumes.
The increase in operating expenses is primarily due to higher labor and rental costs due to increased activity and system expansions, the acquisition of certain assets in the
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 the depreciable lives of certain assets that were idled in 2022.
The increase in interest expense, net is due to higher net borrowings primarily for the Grand Prix Transaction and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.
The increase in income tax expense is primarily due to a smaller release of the valuation allowance in 2023 compared to 2022, the impact of rate changes and a lower benefit related to income allocated to noncontrolling interest that is not taxable to the Company.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to the Company’s joint venture partner in WestTX, partially offset by higher earnings allocated to the Company's joint venture partner in
Year Ended
The decrease in commodity sales reflects lower NGL, natural gas and condensate prices (
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the
The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher NGL, natural gas and condensate volumes.
The increase in operating expenses is primarily due to higher labor, maintenance and rental costs due to increased activity and system expansions, the acquisition of certain assets in the
See “—Review of Segment Performance” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs, computer systems and professional fees.
The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the
During 2022, the Company terminated the previous TRGP senior secured revolving credit facility and the Partnership’s senior secured revolving credit facility. In addition, the Partnership redeemed its 5.375% Senior Notes due 2027 and its 5.875% Senior Notes due 2026. These transactions resulted in a net loss from financing activities.
During 2022, the Company completed the sale of
The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to the Company’s joint venture partner in WestTX.
The premium on repurchase of noncontrolling interests, net of tax is primarily due to the Grand Prix Transaction in 2023 and the purchase of all of Stonepeak Infrastructure Partners’ interests in the Company’s development company joint ventures in 2022.
The decrease in dividends on Series A Preferred Stock (“Series A Preferred”) is due to the full redemption of all of the Company’s issued and outstanding shares of Series A Preferred in
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 |
Year Ended |
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| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | |||||||||||||||||||||||||||||||
| Operating margin | $ | 536.3 | $ | 544.0 | $ | (7.7 | ) | (1 | %) | $ | 2,082.2 | $ | 1,981.0 | $ | 101.2 | 5 | % | ||||||||||||||
| Operating expenses | 185.7 | 177.3 | 8.4 | 5 | % | 746.6 | 611.8 | 134.8 | 22 | % | |||||||||||||||||||||
| Adjusted operating margin | $ | 722.0 | $ | 721.3 | $ | 0.7 | — | $ | 2,828.8 | $ | 2,592.8 | $ | 236.0 | 9 | % | ||||||||||||||||
| Operating statistics (1): | |||||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (2) (3) | |||||||||||||||||||||||||||||||
| Permian Midland (4) | 2,716.5 | 2,376.0 | 340.5 | 14 | % | 2,535.2 | 2,223.6 | 311.6 | 14 | % | |||||||||||||||||||||
| Permian |
2,564.3 | 2,371.3 | 193.0 | 8 | % | 2,526.5 | 1,536.1 | 990.4 | 64 | % | |||||||||||||||||||||
| Total Permian | 5,280.8 | 4,747.3 | 533.5 | 11 | % | 5,061.7 | 3,759.7 | 1,302.0 | 35 | % | |||||||||||||||||||||
| SouthTX (6) | 347.9 | 334.7 | 13.2 | 4 | % | 367.4 | 276.5 | 90.9 | 33 | % | |||||||||||||||||||||
| 207.7 | 219.4 | (11.7 | ) | (5 | %) | 205.9 | 187.0 | 18.9 | 10 | % | |||||||||||||||||||||
| SouthOK (6) | 366.5 | 359.7 | 6.8 | 2 | % | 385.0 | 406.8 | (21.8 | ) | (5 | %) | ||||||||||||||||||||
| WestOK | 207.1 | 207.3 | (0.2 | ) | — | 207.1 | 208.7 | (1.6 | ) | (1 | %) | ||||||||||||||||||||
| Total Central | 1,129.2 | 1,121.1 | 8.1 | 1 | % | 1,165.4 | 1,079.0 | 86.4 | 8 | % | |||||||||||||||||||||
| Badlands (6) (7) | 131.2 | 140.2 | (9.0 | ) | (6 | %) | 130.0 | 134.9 | (4.9 | ) | (4 | %) | |||||||||||||||||||
| Total Field | 6,541.2 | 6,008.6 | 532.6 | 9 | % | 6,357.1 | 4,973.6 | 1,383.5 | 28 | % | |||||||||||||||||||||
| Coastal | 567.0 | 457.3 | 109.7 | 24 | % | 541.1 | 537.6 | 3.5 | 1 | % | |||||||||||||||||||||
| Total | 7,108.2 | 6,465.9 | 642.3 | 10 | % | 6,898.2 | 5,511.2 | 1,387.0 | 25 | % | |||||||||||||||||||||
| NGL production, MBbl/d (3) | |||||||||||||||||||||||||||||||
| Permian Midland (4) | 398.3 | 342.0 | 56.3 | 16 | % | 367.7 | 321.7 | 46.0 | 14 | % | |||||||||||||||||||||
| Permian |
310.6 | 276.1 | 34.5 | 12 | % | 321.6 | 188.6 | 133.0 | 71 | % | |||||||||||||||||||||
| Total Permian | 708.9 | 618.1 | 90.8 | 15 | % | 689.3 | 510.3 | 179.0 | 35 | % | |||||||||||||||||||||
| SouthTX (6) | 37.3 | 34.2 | 3.1 | 9 | % | 40.9 | 31.2 | 9.7 | 31 | % | |||||||||||||||||||||
| 24.5 | 25.2 | (0.7 | ) | (3 | %) | 24.0 | 21.2 | 2.8 | 13 | % | |||||||||||||||||||||
| SouthOK (6) | 40.0 | 36.3 | 3.7 | 10 | % | 43.1 | 47.6 | (4.5 | ) | (9 | %) | ||||||||||||||||||||
| WestOK | 12.1 | 12.1 | — | — | 12.5 | 14.6 | (2.1 | ) | (14 | %) | |||||||||||||||||||||
| Total Central | 113.9 | 107.8 | 6.1 | 6 | % | 120.5 | 114.6 | 5.9 | 5 | % | |||||||||||||||||||||
| Badlands (6) | 15.7 | 17.0 | (1.3 | ) | (8 | %) | 15.5 | 16.1 | (0.6 | ) | (4 | %) | |||||||||||||||||||
| Total Field | 838.5 | 742.9 | 95.6 | 13 | % | 825.3 | 641.0 | 184.3 | 29 | % | |||||||||||||||||||||
| Coastal | 43.2 | 22.9 | 20.3 | 89 | % | 39.2 | 32.0 | 7.2 | 23 | % | |||||||||||||||||||||
| Total | 881.7 | 765.8 | 115.9 | 15 | % | 864.5 | 673.0 | 191.5 | 28 | % | |||||||||||||||||||||
| Crude oil, Badlands, MBbl/d | 105.2 | 113.7 | (8.5 | ) | (7 | %) | 105.5 | 117.6 | (12.1 | ) | (10 | %) | |||||||||||||||||||
| Crude oil, Permian, MBbl/d | 27.5 | 28.4 | (0.9 | ) | (3 | %) | 27.4 | 29.5 | (2.1 | ) | (7 | %) | |||||||||||||||||||
| Natural gas sales, BBtu/d (3) | 2,737.3 | 2,665.3 | 72.0 | 3 | % | 2,685.8 | 2,383.4 | 302.4 | 13 | % | |||||||||||||||||||||
| NGL sales, MBbl/d (3) | 520.6 | 457.6 | 63.0 | 14 | % | 495.8 | 439.8 | 56.0 | 13 | % | |||||||||||||||||||||
| Condensate sales, MBbl/d | 17.8 | 16.3 | 1.5 | 9 | % | 18.5 | 15.5 | 3.0 | 19 | % | |||||||||||||||||||||
| Average realized prices (8): | |||||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 1.83 | 3.94 | (2.11 | ) | (54 | %) | 1.94 | 5.21 | (3.27 | ) | (63 | %) | |||||||||||||||||||
| NGL, $/gal | 0.43 | 0.55 | (0.12 | ) | (22 | %) | 0.46 | 0.75 | (0.29 | ) | (39 | %) | |||||||||||||||||||
| Condensate, $/Bbl | 74.79 | 77.21 | (2.42 | ) | (3 | %) | 74.35 | 88.26 | (13.91 | ) | (16 | %) | |||||||||||||||||||
(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) Includes operations from the acquisition of certain assets in the
(6) Operations include facilities that are not wholly owned by the Company. SouthTX operating statistics include the impact of the acquisition of certain assets in
(7) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
(8) 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) |
||||||||||||||||||
| Natural gas (BBtu) | 13.2 | $ | 1.15 | $ | 15.2 | 20.2 | $ | (0.02 | ) | $ | (0.4 | ) | |||||||||||
| NGL (MMgal) | 165.3 | 0.09 | 15.5 | 187.9 | (0.04 | ) | (7.8 | ) | |||||||||||||||
| Crude oil (MBbl) | 0.6 | (6.17 | ) | (3.7 | ) | 0.6 | (14.22 | ) | (8.5 | ) | |||||||||||||
| $ | 27.0 | $ | (16.7 | ) | |||||||||||||||||||
| Year Ended |
Year 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) | 63.2 | $ | 1.22 | $ | 77.4 | 74.8 | $ | (2.13 | ) | $ | (159.2 | ) | |||||||||||
| NGL (MMgal) | 680.3 | 0.07 | 49.9 | 717.6 | (0.30 | ) | (213.0 | ) | |||||||||||||||
| Crude oil (MBbl) | 2.4 | (6.92 | ) | (16.6 | ) | 2.2 | (31.73 | ) | (69.8 | ) | |||||||||||||
| $ | 110.7 | $ | (442.0 | ) | |||||||||||||||||||
(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 adjusted operating margin was relatively flat and higher natural gas inlet volumes and higher fees predominantly in the Permian were 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, and the Greenwood plant during the fourth quarter of 2023, and continued strong producer activity. The natural gas inlet volumes in the Coastal region increased primarily due to plant outages in the fourth quarter of 2022.
The increase in operating expenses was primarily due to higher volumes in the Permian, the addition of the Legacy II, Midway, Greenwood and Wildcat II plants, increased professional services, and inflation impacts.
Year Ended
The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the
The increase in operating expenses was predominantly due to the acquisition of certain assets in the
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 |
Year Ended |
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| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||||||||||
| (In millions, except operating statistics) | |||||||||||||||||||||||||||||||
| Operating margin | $ | 554.2 | $ | 441.6 | $ | 112.6 | 25 | % | $ | 1,948.7 | $ | 1,456.3 | $ | 492.4 | 34 | % | |||||||||||||||
| Operating expenses | 84.4 | 74.4 | 10.0 | 13 | % | 332.0 | 300.2 | 31.8 | 11 | % | |||||||||||||||||||||
| Adjusted operating margin | $ | 638.6 | $ | 516.0 | $ | 122.6 | 24 | % | $ | 2,280.7 | $ | 1,756.5 | $ | 524.2 | 30 | % | |||||||||||||||
| Operating statistics MBbl/d (1): | |||||||||||||||||||||||||||||||
| NGL pipeline transportation volumes (2) | 722.0 | 502.3 | 219.7 | 44 | % | 635.5 | 488.6 | 146.9 | 30 | % | |||||||||||||||||||||
| Fractionation volumes | 844.8 | 744.4 | 100.4 | 13 | % | 798.1 | 731.7 | 66.4 | 9 | % | |||||||||||||||||||||
| Export volumes (3) | 434.5 | 299.4 | 135.1 | 45 | % | 365.2 | 314.5 | 50.7 | 16 | % | |||||||||||||||||||||
| NGL sales | 1,125.8 | 861.0 | 264.8 | 31 | % | 1,019.8 | 866.3 | 153.5 | 18 | % | |||||||||||||||||||||
(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 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 higher fees. LPG export margin increased due to the completion of the expansion during the third quarter of 2023 resulting in higher volumes and fees. Greater seasonal optimization opportunities drove higher marketing margin in the fourth quarter of 2022.
The increase in operating expenses was due to higher system volumes, higher repairs and maintenance and higher compensation and benefits.
Year 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 higher fees. Marketing margin increased due to greater optimization opportunities. LPG Export margin increased due to the completion of the expansion during the third quarter of 2023 resulting in higher volumes and fees.
The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher repairs and maintenance and higher taxes.
Other
| Three Months Ended |
Year Ended |
||||||||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating margin | $ | (18.8 | ) | $ | (7.5 | ) | $ | (11.3 | ) | $ | 275.5 | $ | (302.4 | ) | $ | 577.9 | |||||||
| Adjusted operating margin | $ | (18.8 | ) | $ | (7.5 | ) | $ | (11.3 | ) | $ | 275.5 | $ | (302.4 | ) | $ | 577.9 | |||||||
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, distributable cash flow, 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, distributable cash flow, 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
Distributable Cash Flow and Adjusted Free Cash Flow
The Company defines distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Company defines adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow 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 |
Year Ended |
||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||
| (In millions) | |||||||||||||||
| Reconciliation of Net income (loss) attributable to |
|||||||||||||||
| Net income (loss) attributable to |
$ | 299.6 | $ | 318.0 | $ | 1,345.9 | $ | 1,195.5 | |||||||
| Interest (income) expense, net | 178.0 | 145.6 | 687.8 | 446.1 | |||||||||||
| Income tax expense (benefit) | 102.5 | 9.8 | 363.2 | 131.8 | |||||||||||
| Depreciation and amortization expense | 341.4 | 329.8 | 1,329.6 | 1,096.0 | |||||||||||
| (Gain) loss on sale or disposition of assets | (1.3 | ) | (1.5 | ) | (5.3 | ) | (9.6 | ) | |||||||
| Write-down of assets | 0.8 | 6.2 | 6.9 | 9.8 | |||||||||||
| (Gain) loss from financing activities (1) | 2.1 | — | 2.1 | 49.6 | |||||||||||
| (Gain) loss from sale of equity method investment | — | — | — | (435.9 | ) | ||||||||||
| Transaction costs related to business acquisition (2) | — | 3.6 | — | 23.9 | |||||||||||
| Equity (earnings) loss | (2.8 | ) | (0.3 | ) | (9.0 | ) | (9.1 | ) | |||||||
| Distributions (contributions) from unconsolidated affiliates, net | 4.5 | 5.5 | 18.6 | 27.2 | |||||||||||
| Compensation on equity grants | 16.7 | 15.7 | 62.4 | 57.5 | |||||||||||
| Risk management activities | 18.8 | 7.5 | (275.4 | ) | 302.5 | ||||||||||
| Noncontrolling interests adjustments (3) | (0.4 | ) | 0.5 | (3.7 | ) | 15.8 | |||||||||
| Litigation expense (4) | — | — | 6.9 | — | |||||||||||
| Adjusted EBITDA | $ | 959.9 | $ | 840.4 | $ | 3,530.0 | $ | 2,901.1 | |||||||
| Interest expense on debt obligations (5) | (174.9 | ) | (142.5 | ) | (675.8 | ) | (447.6 | ) | |||||||
| Maintenance capital expenditures, net (6) | (70.4 | ) | (41.3 | ) | (223.4 | ) | (168.1 | ) | |||||||
| Cash taxes | (4.9 | ) | (1.1 | ) | (13.6 | ) | (6.7 | ) | |||||||
| Distributable Cash Flow | $ | 709.7 | $ | 655.5 | $ | 2,617.2 | $ | 2,278.7 | |||||||
| Growth capital expenditures, net (6) | (636.0 | ) | (552.4 | ) | (2,224.5 | ) | (1,177.2 | ) | |||||||
| Adjusted Free Cash Flow | $ | 73.7 | $ | 103.1 | $ | 392.7 | $ | 1,101.5 | |||||||
(1) Gains or losses on debt repurchases or early debt extinguishments.
(2) Includes financial advisory, legal and other professional fees, and other one-time transaction costs.
(3) Noncontrolling interest portion of depreciation and amortization expense.
(4) Litigation expense includes charges related to litigation resulting from the major winter storm in
(5) Excludes amortization of debt issuance costs.
(6) Represents capital expenditures, net of contributions from noncontrolling interests and includes net 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 |
$ | 1,185.0 | |
| Interest expense, net | 730.0 | ||
| Income tax expense | 475.0 | ||
| Depreciation and amortization expense | 1,350.0 | ||
| Equity earnings | (15.0 | ) | |
| Distributions from unconsolidated affiliates | 20.0 | ||
| Compensation on equity grants | 65.0 | ||
| Risk management and other | — | ||
| Noncontrolling interests adjustments (1) | (10.0 | ) | |
| Estimated Adjusted EBITDA | $ | 3,800.0 | |
(1) 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
Chief Financial Officer
Source: Targa Resources Corp.