Targa Resources Corp. Reports Third Quarter 2022 Financial Results
Third Quarter 2022 Financial Results
Third quarter 2022 net income attributable to
The Company reported record adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of
On
Targa repurchased 1,156,832 shares of its common stock during the third quarter of 2022 at a weighted average price of
The Company reported distributable cash flow and adjusted free cash flow for the third quarter of 2022 of
Third Quarter 2022 -
Targa reported third quarter 2022 adjusted EBITDA of
Capitalization and Liquidity
In
The Company’s total consolidated debt as of
Total consolidated liquidity as of
Growth Projects Update
During the third quarter, Targa commenced operations at its new 275 million cubic feet per day (“MMcf/d”) Legacy plant in Permian Midland and its new 230 MMcf/d Red Hills VI plant in Permian Delaware.
Construction continues on Targa’s 275 MMcf/d Legacy II plant and 275 MMcf/d Greenwood plant in Permian Midland, its 275 MMcf/d Midway plant in Permian Delaware, and its 120 thousand barrels per day (“MBbl/d”) Train 9 fractionator in
In
In
2022 Outlook
While commodity prices were significantly lower in the third quarter than the assumptions underlying Targa’s last provided financial estimates for 2022, there is no change to the Company’s expectation to generate full year adjusted EBITDA between
Through
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
| Three Months Ended |
Nine Months Ended |
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| 2022 | 2021 | 2022 vs. 2021 | 2022 | 2021 | 2022 vs. 2021 | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||
| Sales of commodities | $ | 4,800.3 | $ | 4,118.1 | $ | 682.2 | 17 | % | $ | 14,990.7 | $ | 10,577.3 | $ | 4,413.4 | 42 | % | ||||||||||||||
| Fees from midstream services | 559.8 | 341.6 | 218.2 | 64 | % | 1,384.3 | 930.9 | 453.4 | 49 | % | ||||||||||||||||||||
| Total revenues | 5,360.1 | 4,459.7 | 900.4 | 20 | % | 16,375.0 | 11,508.2 | 4,866.8 | 42 | % | ||||||||||||||||||||
| Product purchases and fuel | 4,306.3 | 3,614.7 | 691.6 | 19 | % | 13,557.8 | 9,159.8 | 4,398.0 | 48 | % | ||||||||||||||||||||
| Operating expenses | 261.3 | 189.4 | 71.9 | 38 | % | 660.6 | 545.3 | 115.3 | 21 | % | ||||||||||||||||||||
| Depreciation and amortization expense | 287.2 | 222.8 | 64.4 | 29 | % | 766.2 | 650.9 | 115.3 | 18 | % | ||||||||||||||||||||
| General and administrative expense | 79.1 | 67.3 | 11.8 | 18 | % | 217.2 | 192.4 | 24.8 | 13 | % | ||||||||||||||||||||
| Other operating (income) expense | (3.8 | ) | (1.0 | ) | (2.8 | ) | 280 | % | (4.4 | ) | 3.4 | (7.8 | ) | (229 | %) | |||||||||||||||
| Income (loss) from operations | 430.0 | 366.5 | 63.5 | 17 | % | 1,177.6 | 956.4 | 221.2 | 23 | % | ||||||||||||||||||||
| Interest expense, net | (125.8 | ) | (91.0 | ) | (34.8 | ) | 38 | % | (300.5 | ) | (284.2 | ) | (16.3 | ) | 6 | % | ||||||||||||||
| Equity earnings (loss) | 1.7 | 14.3 | (12.6 | ) | (88 | %) | 8.7 | 38.9 | (30.2 | ) | (78 | %) | ||||||||||||||||||
| Gain (loss) from financing activities | — | — | — | — | (49.6 | ) | (16.6 | ) | (33.0 | ) | 199 | % | ||||||||||||||||||
| Gain (loss) from sale of equity method investment | — | — | — | — | 435.9 | — | 435.9 | 100 | % | |||||||||||||||||||||
| Other, net | (14.6 | ) | 0.2 | (14.8 | ) | NM | (14.6 | ) | 0.3 | (14.9 | ) | NM | ||||||||||||||||||
| Income tax (expense) benefit | (12.0 | ) | (2.0 | ) | (10.0 | ) | NM | (122.0 | ) | (23.5 | ) | (98.5 | ) | NM | ||||||||||||||||
| Net income (loss) | 279.3 | 288.0 | (8.7 | ) | (3 | %) | 1,135.5 | 671.3 | 464.2 | 69 | % | |||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 86.2 | 105.8 | (19.6 | ) | (19 | %) | 258.0 | 286.5 | (28.5 | ) | (10 | %) | ||||||||||||||||||
| Net income (loss) attributable to |
193.1 | 182.2 | 10.9 | 6 | % | 877.5 | 384.8 | 492.7 | 128 | % | ||||||||||||||||||||
| Premium on repurchase of noncontrolling interests, net of tax | — | — | — | — | 53.1 | — | 53.1 | 100 | % | |||||||||||||||||||||
| Dividends on Series A Preferred Stock | — | 21.8 | (21.8 | ) | (100 | %) | 30.0 | 65.5 | (35.5 | ) | (54 | %) | ||||||||||||||||||
| Deemed dividends on Series A Preferred Stock | — | — | — | — | 215.5 | — | 215.5 | 100 | % | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 193.1 | $ | 160.4 | $ | 32.7 | 20 | % | $ | 578.9 | $ | 319.3 | $ | 259.6 | 81 | % | ||||||||||||||
| Financial data: | ||||||||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 768.6 | $ | 505.9 | $ | 262.7 | 52 | % | $ | 2,060.8 | $ | 1,481.4 | $ | 579.4 | 39 | % | ||||||||||||||
| Distributable cash flow (1) | 594.9 | 383.9 | 211.0 | 55 | % | 1,623.2 | 1,120.7 | 502.5 | 45 | % | ||||||||||||||||||||
| Adjusted free cash flow (1) | 290.8 | 297.2 | (6.4 | ) | (2 | %) | 998.4 | 892.8 | 105.6 | 12 | % | |||||||||||||||||||
__________________
(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 or material.
Three Months Ended
The increase in commodity sales reflects higher 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 increase in product purchases and fuel reflects higher natural gas and condensate prices and higher NGL and natural gas volumes, partially offset by lower NGL prices.
The increase in operating expenses is due to higher compensation and benefits, maintenance and rental costs primarily due to increased activity, 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 and professional fees.
The increase in interest expense, net is primarily due to higher net borrowings, partially offset by higher capitalized interest resulting from higher growth capital investments.
The decrease in equity earnings is primarily due to the sale of
The increase in income tax expense is primarily due to a lower return-to-provision benefit in 2022 compared to 2021.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the repurchase of the Company's development company joint ventures in
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 during 2022.
Nine Months Ended
The increase in commodity sales reflects higher 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 increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.
The increase in operating expenses is due to higher maintenance, compensation and benefits, and rental costs primarily due to increased activity, 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 increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.
The increase in interest expense, net is primarily due to higher net borrowings and higher non-cash interest expense related to an increase in the mandatorily redeemable preferred interest liability, partially offset by change in fair value of the mandatorily redeemable preferred interest, higher capitalized interest resulting from higher growth capital investments and lower commitment fees.
The decrease in equity earnings is primarily due to the GCX Sale and lower earnings from the Company's investment in
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 the 5.375% Senior Notes due 2027 and the 5.875% Senior Notes due 2026. These transactions resulted in a net loss from financing activities. During 2021, the Partnership redeemed its 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due 2023. In addition,
During 2022, the Company completed the GCX Sale resulting in a gain from sale of an equity method investment.
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in 2022 compared to 2021.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the DevCo JV Repurchase, partially offset by accretion of noncontrolling interests in certain joint ventures in WestTX and higher income allocated to noncontrolling interests holders in the Grand Prix Joint Venture,
The decrease in dividends on Series A Preferred is due to the full redemption of all of the Company's issued and outstanding shares of Series A Preferred during 2022.
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 |
Nine Months Ended |
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| 2022 | 2021 | 2022 vs. 2021 | 2022 | 2021 | 2022 vs. 2021 | ||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | |||||||||||||||||||||||||||||
| Operating margin | $ | 564.6 | $ | 361.4 | $ | 203.2 | 56 | % | $ | 1,437.0 | $ | 938.2 | $ | 498.8 | 53 | % | |||||||||||||
| Operating expenses | 176.6 | 122.8 | 53.8 | 44 | % | 434.5 | 343.1 | 91.4 | 27 | % | |||||||||||||||||||
| Adjusted operating margin | $ | 741.2 | $ | 484.2 | $ | 257.0 | 53 | % | $ | 1,871.5 | $ | 1,281.3 | $ | 590.2 | 46 | % | |||||||||||||
| Operating statistics (1): | |||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (2),(3) | |||||||||||||||||||||||||||||
| Permian Midland (4) | 2,307.2 | 2,044.7 | 262.5 | 13 | % | 2,172.3 | 1,878.9 | 293.4 | 16 | % | |||||||||||||||||||
| Permian |
1,784.8 | 842.7 | 942.1 | 112 | % | 1,254.6 | 805.9 | 448.7 | 56 | % | |||||||||||||||||||
| Total Permian | 4,092.0 | 2,887.4 | 1,204.6 | 3,426.9 | 2,684.8 | 742.1 | |||||||||||||||||||||||
| SouthTX (6) | 335.5 | 180.5 | 155.0 | 86 | % | 256.9 | 184.0 | 72.9 | 40 | % | |||||||||||||||||||
| 177.7 | 180.7 | (3.0 | ) | (2 | %) | 176.1 | 179.2 | (3.1 | ) | (2 | %) | ||||||||||||||||||
| SouthOK (6) | 400.4 | 420.6 | (20.2 | ) | (5 | %) | 422.7 | 402.6 | 20.1 | 5 | % | ||||||||||||||||||
| WestOK | 212.8 | 219.4 | (6.6 | ) | (3 | %) | 209.1 | 211.6 | (2.5 | ) | (1 | %) | |||||||||||||||||
| Total Central | 1,126.4 | 1,001.2 | 125.2 | 1,064.8 | 977.4 | 87.4 | |||||||||||||||||||||||
| Badlands (6) (7) | 144.8 | 135.2 | 9.6 | 7 | % | 133.1 | 137.8 | (4.7 | ) | (3 | %) | ||||||||||||||||||
| Total Field | 5,363.2 | 4,023.8 | 1,339.4 | 4,624.8 | 3,800.0 | 824.8 | |||||||||||||||||||||||
| Coastal | 539.1 | 527.1 | 12.0 | 2 | % | 564.7 | 598.3 | (33.6 | ) | (6 | %) | ||||||||||||||||||
| Total | 5,902.3 | 4,550.9 | 1,351.4 | 30 | % | 5,189.5 | 4,398.3 | 791.2 | 18 | % | |||||||||||||||||||
| NGL production, MBbl/d (3) | |||||||||||||||||||||||||||||
| Permian Midland (4) | 332.6 | 293.8 | 38.8 | 13 | % | 314.8 | 270.3 | 44.5 | 16 | % | |||||||||||||||||||
| Permian |
219.2 | 119.8 | 99.4 | 83 | % | 161.8 | 109.3 | 52.5 | 48 | % | |||||||||||||||||||
| Total Permian | 551.8 | 413.6 | 138.2 | 476.6 | 379.6 | 97.0 | |||||||||||||||||||||||
| SouthTX (6) | 36.4 | 24.2 | 12.2 | 50 | % | 30.1 | 22.6 | 7.5 | 33 | % | |||||||||||||||||||
| 20.5 | 21.0 | (0.5 | ) | (2 | %) | 19.8 | 20.2 | (0.4 | ) | (2 | %) | ||||||||||||||||||
| SouthOK (6) | 48.1 | 52.1 | (4.0 | ) | (8 | %) | 51.4 | 48.8 | 2.6 | 5 | % | ||||||||||||||||||
| WestOK | 14.8 | 15.7 | (0.9 | ) | (6 | %) | 15.4 | 16.2 | (0.8 | ) | (5 | %) | |||||||||||||||||
| Total Central | 119.8 | 113.0 | 6.8 | 116.7 | 107.8 | 8.9 | |||||||||||||||||||||||
| Badlands (6) | 18.0 | 16.2 | 1.8 | 11 | % | 15.8 | 16.0 | (0.2 | ) | (1 | %) | ||||||||||||||||||
| Total Field | 689.6 | 542.8 | 146.8 | 609.1 | 503.4 | 105.7 | |||||||||||||||||||||||
| Coastal | 31.7 | 28.0 | 3.7 | 13 | % | 35.1 | 34.5 | 0.6 | 2 | % | |||||||||||||||||||
| Total | 721.3 | 570.8 | 150.5 | 26 | % | 644.2 | 537.9 | 106.3 | 20 | % | |||||||||||||||||||
| Crude oil, Badlands, MBbl/d | 122.2 | 140.8 | (18.6 | ) | (13 | %) | 118.9 | 138.7 | (19.8 | ) | (14 | %) | |||||||||||||||||
| Crude oil, Permian, MBbl/d | 30.3 | 34.1 | (3.8 | ) | (11 | %) | 29.9 | 35.3 | (5.4 | ) | (15 | %) | |||||||||||||||||
| Natural gas sales, BBtu/d (3) | 2,458.1 | 2,319.9 | 138.2 | 6 | % | 2,288.4 | 2,162.5 | 125.9 | 6 | % | |||||||||||||||||||
| NGL sales, MBbl/d (3) | 436.1 | 412.6 | 23.5 | 6 | % | 433.8 | 384.7 | 49.1 | 13 | % | |||||||||||||||||||
| Condensate sales, MBbl/d | 15.5 | 15.4 | 0.1 | 1 | % | 15.2 | 15.3 | (0.1 | ) | (1 | %) | ||||||||||||||||||
| Average realized prices - inclusive of hedges (8): | |||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 6.71 | 3.51 | 3.20 | 91 | % | 5.71 | 2.85 | 2.86 | 100 | % | |||||||||||||||||||
| NGL, $/gal | 0.77 | 0.69 | 0.08 | 12 | % | 0.82 | 0.56 | 0.26 | 46 | % | |||||||||||||||||||
| Condensate, $/Bbl | 96.41 | 64.41 | 32.00 | 50 | % | 92.25 | 56.86 | 35.39 | 62 | % | |||||||||||||||||||
__________________
(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 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 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.
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) | 20.3 | $ | (3.58 | ) | $ | (72.7 | ) | 20.5 | $ | (1.52 | ) | $ | (31.2 | ) | ||||||||||
| NGL (MMgal) | 194.9 | (0.25 | ) | (49.4 | ) | 150.4 | (0.35 | ) | (52.4 | ) | ||||||||||||||
| Crude oil (MBbl) | 0.6 | (26.83 | ) | (16.1 | ) | 0.5 | (18.80 | ) | (9.4 | ) | ||||||||||||||
| $ | (138.2 | ) | $ | (93.0 | ) | |||||||||||||||||||
__________________
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
| Nine Months Ended |
Nine 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) | 54.5 | $ | (2.91 | ) | $ | (158.8 | ) | 56.6 | $ | (1.01 | ) | $ | (57.2 | ) | ||||||||||
| NGL (MMgal) | 529.7 | (0.39 | ) | (205.2 | ) | 420.0 | (0.24 | ) | (99.3 | ) | ||||||||||||||
| Crude oil (MBbl) | 1.6 | (38.31 | ) | (61.3 | ) | 1.6 | (11.38 | ) | (18.2 | ) | ||||||||||||||
| $ | (425.3 | ) | $ | (174.7 | ) | |||||||||||||||||||
__________________
(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
The increase in adjusted operating margin was due to higher natural gas inlet volumes, higher realized commodity prices and higher fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to both the acquisition of certain assets in the
The increase in operating expenses was predominantly due to the acquisition of certain assets in
Nine Months Ended
The increase in adjusted operating margin was due to higher realized commodity prices, higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to both the acquisition of certain assets in the
The increase in operating expenses was predominantly due to the acquisition of certain assets in
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 |
Nine Months Ended |
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| 2022 | 2021 | 2022 vs. 2021 | 2022 | 2021 | 2022 vs. 2021 | ||||||||||||||||||||
| (In millions, except operating statistics) | |||||||||||||||||||||||||
| Operating margin | $ | 340.2 | $ | 280.7 | $ | 59.5 | 21 | % | $ | 1,014.6 | $ | 920.5 | $ | 94.1 | 10 | % | |||||||||
| Operating expenses | 84.5 | 67.3 | 17.2 | 26 | % | 225.8 | 204.1 | 21.7 | 11 | % | |||||||||||||||
| Adjusted operating margin | $ | 424.7 | $ | 348.0 | $ | 76.7 | 22 | % | $ | 1,240.4 | $ | 1,124.6 | $ | 115.8 | 10 | % | |||||||||
| Operating statistics MBbl/d (1): | |||||||||||||||||||||||||
| NGL pipeline transportation volumes (2) | 499.5 | 416.5 | 83.0 | 20 | % | 484.0 | 383.8 | 100.2 | 26 | % | |||||||||||||||
| Fractionation volumes | 742.1 | 662.0 | 80.1 | 12 | % | 727.5 | 617.5 | 110.0 | 18 | % | |||||||||||||||
| Export volumes (3) | 276.1 | 293.2 | (17.1 | ) | (6 | %) | 319.6 | 305.7 | 13.9 | 5 | % | ||||||||||||||
| NGL sales | 825.0 | 792.1 | 32.9 | 4 | % | 868.1 | 817.6 | 50.5 | 6 | % | |||||||||||||||
__________________
(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 marketing margin, partially offset by lower 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 decreased primarily due to higher fuel and power costs and lower volumes.
The increase in operating expenses was due to higher repairs and maintenance and higher compensation and benefits.
Nine Months Ended
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation 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. Higher optimization margin attributable to the winter storm resulted in higher marketing margin in 2021.
The increase in operating expenses was primarily due to higher repairs and maintenance and higher compensation and benefits, partially offset by lower taxes.
Other
| Three Months Ended |
Nine Months Ended |
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| 2022 | 2021 | 2022 vs. 2021 | 2022 | 2021 | 2022 vs. 2021 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating margin | $ | (112.2 | ) | $ | 13.5 | $ | (125.7 | ) | $ | (294.9 | ) | $ | (55.6 | ) | $ | (239.3 | ) | |||||||
| Adjusted operating margin | $ | (112.2 | ) | $ | 13.5 | $ | (125.7 | ) | $ | (294.9 | ) | $ | (55.6 | ) | $ | (239.3 | ) | |||||||
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 |
Nine Months Ended |
||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||
| (In millions) | |||||||||||||||||||
| Reconciliation of Net income (loss) attributable to |
|||||||||||||||||||
| Net income (loss) attributable to |
$ | 193.1 | $ | 182.2 | $ | 877.5 | $ | 384.8 | |||||||||||
| Interest (income) expense, net | 125.8 | 91.0 | 300.5 | 284.2 | |||||||||||||||
| Income tax expense (benefit) | 12.0 | 2.0 | 122.0 | 23.5 | |||||||||||||||
| Depreciation and amortization expense | 287.2 | 222.8 | 766.2 | 650.9 | |||||||||||||||
| (Gain) loss on sale or disposition of assets | (6.5 | ) | (1.5 | ) | (8.1 | ) | (1.7 | ) | |||||||||||
| Write-down of assets | 2.7 | 0.5 | 3.7 | 5.0 | |||||||||||||||
| (Gain) loss from financing activities (1) | — | — | 49.6 | 16.6 | |||||||||||||||
| (Gain) loss from sale of equity method investment | — | — | (435.9 | ) | — | ||||||||||||||
| Transaction costs related to business acquisitions (2) | 20.3 | — | 20.3 | — | |||||||||||||||
| Equity (earnings) loss | (1.7 | ) | (14.3 | ) | (8.7 | ) | (38.9 | ) | |||||||||||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 2.4 | 28.2 | 21.7 | 88.4 | |||||||||||||||
| Compensation on equity grants | 14.4 | 14.7 | 41.8 | 44.6 | |||||||||||||||
| Risk management activities | 112.2 | (12.6 | ) | 295.0 | 55.6 | ||||||||||||||
| Noncontrolling interests adjustments (3) | 6.7 | (7.1 | ) | 15.2 | (31.6 | ) | |||||||||||||
| Adjusted EBITDA | $ | 768.6 | $ | 505.9 | $ | 2,060.8 | $ | 1,481.4 | |||||||||||
| Interest expense on debt obligations (4) | (123.0 | ) | (91.6 | ) | (305.2 | ) | (285.8 | ) | |||||||||||
| Maintenance capital expenditures, net (5) | (49.4 | ) | (29.6 | ) | (126.8 | ) | (72.9 | ) | |||||||||||
| Cash taxes | (1.3 | ) | (0.8 | ) | (5.6 | ) | (2.0 | ) | |||||||||||
| Distributable Cash Flow | $ | 594.9 | $ | 383.9 | $ | 1,623.2 | $ | 1,120.7 | |||||||||||
| Growth capital expenditures, net (5) | (304.1 | ) | (86.7 | ) | (624.8 | ) | (227.9 | ) | |||||||||||
| Adjusted Free Cash Flow | $ | 290.8 | $ | 297.2 | $ | 998.4 | $ | 892.8 | |||||||||||
__________________
(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) Excludes amortization of interest expense.
(5) 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 2022:
| 2022E | |||
| (In millions) | |||
| Reconciliation of Estimated Net Income attributable to |
|||
| Estimated Adjusted EBITDA | |||
| Net income attributable to |
$ | 1,245.0 | |
| Interest expense, net | 400.0 | ||
| Income tax expense | 340.0 | ||
| Depreciation and amortization expense | 1,050.0 | ||
| Gain from sale of equity method investment | (440.0 | ) | |
| Equity earnings | (14.0 | ) | |
| Loss from financing activities (1) | 50.0 | ||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 40.0 | ||
| Compensation on equity grants | 55.0 | ||
| Risk management and other | 180.0 | ||
| Noncontrolling interests adjustments (2) | (6.0 | ) | |
| Estimated Adjusted EBITDA | $ | 2,900.0 | |
(1) Losses on debt repurchases or early debt extinguishments.
(2) Noncontrolling interest portion of depreciation and amortization expense.
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. 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, 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 impact of pandemics or any other public health crises, commodity price volatility due to ongoing or new global conflicts, 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.