Targa Resources Corp. Reports Fourth Quarter and Full Year 2021 Financial Results and Provides 2022 Operational and Financial Outlook
Fourth Quarter and Full Year 2021 Financial Results
Fourth quarter 2021 net income (loss) attributable to
The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of
On
The Company reported distributable cash flow and adjusted free cash flow for the fourth quarter of 2021 of
Fourth Quarter 2021 -
Targa reported fourth quarter 2021 adjusted EBITDA of
Capitalization and Liquidity
The Company’s total consolidated debt as of
Total consolidated liquidity as of
Financing Update
In
Common Share Repurchases
In the fourth quarter of 2021, Targa repurchased 756,478 shares of its common stock at a weighted average price of
Growth Projects Update
In response to increasing production and to meet the infrastructure needs of producers, Targa announced today its plans to construct a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy II plant”), which is expected to begin operations in the second quarter of 2023. The Company previously announced that it was ordering long-lead items for the Legacy II plant and some growth capital spending for the Legacy II plant was included in the fourth quarter of 2021.
Targa also announced today its plans to construct a new 275 MMcf/d cryogenic natural gas processing plant (the “Midway plant”), which will be located between, and connected to, Targa’s existing Permian Delaware and Permian Midland systems. The Midway plant will process volumes currently flowing to Targa’s
2022 Operational and Financial Expectations
Targa’s operational and financial expectations assume natural gas liquids (“NGL”) composite barrel prices average
For 2022, Targa estimates full year adjusted EBITDA to be between
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 |
Year Ended |
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| 2021 | 2020 | 2021 vs. 2020 | 2021 | 2020 | 2021 vs. 2020 | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||
| Sales of commodities | $ | 5,025.1 | $ | 2,270.2 | $ | 2,754.9 | 121 | % | $ | 15,602.5 | $ | 7,171.0 | $ | 8,431.5 | 118 | % | ||||||||||||||
| Fees from midstream services | 416.5 | 302.6 | 113.9 | 38 | % | 1,347.3 | 1,089.3 | 258.0 | 24 | % | ||||||||||||||||||||
| Total revenues | 5,441.6 | 2,572.8 | 2,868.8 | 112 | % | 16,949.8 | 8,260.3 | 8,689.5 | 105 | % | ||||||||||||||||||||
| Product purchases and fuel (1) | 4,569.7 | 1,781.3 | 2,788.4 | 157 | % | 13,729.5 | 5,186.5 | 8,543.0 | 165 | % | ||||||||||||||||||||
| Operating expenses (1) | 201.7 | 191.7 | 10.0 | 5 | % | 747.0 | 698.4 | 48.6 | 7 | % | ||||||||||||||||||||
| Depreciation and amortization expense | 219.7 | 217.8 | 1.9 | 1 | % | 870.6 | 865.1 | 5.5 | 1 | % | ||||||||||||||||||||
| General and administrative expense | 80.7 | 74.0 | 6.7 | 9 | % | 273.2 | 254.6 | 18.6 | 7 | % | ||||||||||||||||||||
| Impairment of long-lived assets | 452.3 | — | 452.3 | 100 | % | 452.3 | 2,442.8 | (1,990.5 | ) | (81 | %) | |||||||||||||||||||
| Other operating (income) expense | 9.0 | 42.8 | (33.8 | ) | (79 | %) | 12.4 | 116.6 | (104.2 | ) | (89 | %) | ||||||||||||||||||
| Income (loss) from operations | (91.5 | ) | 265.2 | (356.7 | ) | (135 | %) | 864.8 | (1,303.7 | ) | 2,168.5 | 166 | % | |||||||||||||||||
| Interest expense, net | (103.7 | ) | (98.9 | ) | (4.8 | ) | 5 | % | (387.9 | ) | (391.3 | ) | 3.4 | 1 | % | |||||||||||||||
| Equity earnings (loss) | (62.8 | ) | 18.5 | (81.3 | ) | NM | (23.9 | ) | 72.6 | (96.5 | ) | (133 | %) | |||||||||||||||||
| Gain (loss) from financing activities | — | (1.8 | ) | 1.8 | 100 | % | (16.6 | ) | 45.6 | (62.2 | ) | (136 | %) | |||||||||||||||||
| Change in contingent considerations | (0.1 | ) | 0.3 | (0.4 | ) | (133 | %) | (0.1 | ) | 0.3 | (0.4 | ) | (133 | %) | ||||||||||||||||
| Other, net | 0.2 | 1.2 | (1.0 | ) | (83 | %) | 0.6 | 3.4 | (2.8 | ) | (82 | %) | ||||||||||||||||||
| Income tax (expense) benefit | 8.7 | (38.5 | ) | 47.2 | 123 | % | (14.8 | ) | 248.1 | (262.9 | ) | (106 | %) | |||||||||||||||||
| Net income (loss) | (249.2 | ) | 146.0 | (395.2 | ) | (271 | %) | 422.1 | (1,325.0 | ) | 1,747.1 | 132 | % | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 64.4 | 112.4 | (48.0 | ) | (43 | %) | 350.9 | 228.9 | 122.0 | 53 | % | |||||||||||||||||||
| Net income (loss) attributable to |
(313.6 | ) | 33.6 | (347.2 | ) | NM | 71.2 | (1,553.9 | ) | 1,625.1 | 105 | % | ||||||||||||||||||
| Dividends on Series A Preferred Stock | 21.8 | 22.9 | (1.1 | ) | (5 | %) | 87.3 | 91.7 | (4.4 | ) | (5 | %) | ||||||||||||||||||
| Deemed dividends on Series A Preferred Stock | — | 11.5 | (11.5 | ) | (100 | %) | — | 39.2 | (39.2 | ) | (100 | %) | ||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | (335.4 | ) | $ | (0.8 | ) | $ | (334.6 | ) | NM | $ | (16.1 | ) | $ | (1,684.8 | ) | $ | 1,668.7 | 99 | % | ||||||||||
| Financial data: | ||||||||||||||||||||||||||||||
| Adjusted EBITDA (2) | $ | 570.6 | $ | 438.1 | $ | 132.5 | 30 | % | $ | 2,052.0 | $ | 1,636.6 | $ | 415.4 | 25 | % | ||||||||||||||
| Distributable cash flow (2) | 420.7 | 293.9 | 126.8 | 43 | % | 1,541.4 | 1,172.8 | 368.6 | 31 | % | ||||||||||||||||||||
| Adjusted free cash flow (2) | 240.8 | 214.5 | 26.3 | 12 | % | 1,133.7 | 574.9 | 558.8 | 97 | % | ||||||||||||||||||||
| (1) | Beginning in 2021, the Company reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to Targa’s revenue-generating activities and align with the Company’s evaluation of the performance of the business. |
| (2) | 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 NGL, natural gas and condensate prices (
The increase in fees from midstream services is primarily due to higher gathering and gas processing fees.
The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.
See “—Review of Segment Performance” for additional information on a segment basis.
The increase in general and administrative expense was primarily due to higher compensation and benefits.
In 2021, the Company recognized a non-cash pre-tax impairment loss of
Other operating (income) expense in 2021 and 2020 consisted primarily of write-downs of certain assets to their recoverable amounts.
The decrease in equity earnings is primarily due to non-cash pre-tax impairment losses of
The increase in income tax benefit is primarily due to lower pre-tax book income.
The decrease in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling interest holders in the fourth quarter of 2021, partially offset by higher income allocated to noncontrolling interest holders in Grand Prix Joint Venture.
The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.
Year 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 and fractionation volumes, partially offset by lower terminaling and storage fees.
The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes, partially offset by lower petroleum products, crude marketing and condensate volumes.
The increase in operating expenses was due to higher labor costs and repairs and maintenance primarily due to increased activity levels and system expansions, partially offset by the reduction in expense due to the idling of GCF in 2021.
See “—Review of Segment Performance” for additional information on a segment basis.
The increase in general and administrative expense was primarily due to higher compensation and benefits and an increase in insurance costs.
In 2021, the Company recognized a non-cash pre-tax impairment loss of
Other operating (income) expense in 2021 consisted primarily of the write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of the Company’s assets in
The decrease in equity earnings is primarily due to non-cash pre-tax impairment losses of
During 2021, the Partnership redeemed the 5⅛% Notes and the 4¼%
The increase in income tax expense is primarily due to an increase in pre-tax book income.
The increase in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling interest holders in the first quarter of 2020 and higher income allocated to noncontrolling interest holders in Grand Prix Joint Venture. The increase in net income attributable to noncontrolling interests was partially offset by impairment losses allocated to noncontrolling interest holders in the fourth quarter of 2021 and the impact of the redemption of the Partnership’s preferred units in
The decrease in dividends on Series A Preferred is due to the partial repurchase of the Company’s Series A Preferred in
The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.
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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| 2021 | 2020 | 2021 vs. 2020 | 2021 | 2020 | 2021 vs. 2020 | ||||||||||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | |||||||||||||||||||||||||||||||||||||
| Operating margin | $ | 387.1 | $ | 263.9 | $ | 123.2 | 47 | % | $ | 1,325.3 | $ | 1,017.7 | $ | 307.6 | 30 | % | |||||||||||||||||||||
| Operating expenses (1) | 133.1 | 116.1 | 17.0 | 15 | % | 476.2 | 429.9 | 46.3 | 11 | % | |||||||||||||||||||||||||||
| Adjusted operating margin (1) | $ | 520.2 | $ | 380.0 | $ | 140.2 | 37 | % | $ | 1,801.5 | $ | 1,447.6 | $ | 353.9 | 24 | % | |||||||||||||||||||||
| Operating statistics (2): | |||||||||||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (3),(4) | |||||||||||||||||||||||||||||||||||||
| Permian Midland (5) | 2,075.4 | 1,815.4 | 260.0 | 14 | % | 1,928.4 | 1,745.6 | 182.8 | 10 | % | |||||||||||||||||||||||||||
| Permian |
940.5 | 779.8 | 160.7 | 21 | % | 839.8 | 729.4 | 110.4 | 15 | % | |||||||||||||||||||||||||||
| Total Permian | 3,015.9 | 2,595.2 | 420.7 | 2,768.2 | 2,475.0 | 293.2 | |||||||||||||||||||||||||||||||
| SouthTX (6) | 159.2 | 208.0 | (48.8 | ) | (23 | %) | 177.7 | 248.1 | (70.4 | ) | (28 | %) | |||||||||||||||||||||||||
| 178.2 | 187.4 | (9.2 | ) | (5 | %) | 178.9 | 201.6 | (22.7 | ) | (11 | %) | ||||||||||||||||||||||||||
| SouthOK (6) | 415.9 | 382.4 | 33.5 | 9 | % | 405.9 | 443.0 | (37.1 | ) | (8 | %) | ||||||||||||||||||||||||||
| WestOK | 215.5 | 222.2 | (6.7 | ) | (3 | %) | 212.6 | 249.5 | (36.9 | ) | (15 | %) | |||||||||||||||||||||||||
| Total Central | 968.8 | 1,000.0 | (31.2 | ) | 975.1 | 1,142.2 | (167.1 | ) | |||||||||||||||||||||||||||||
| Badlands (6) (7) | 145.9 | 142.8 | 3.1 | 2 | % | 139.8 | 137.8 | 2.0 | 1 | % | |||||||||||||||||||||||||||
| Total Field | 4,130.6 | 3,738.0 | 392.6 | 3,883.1 | 3,755.0 | 128.1 | |||||||||||||||||||||||||||||||
| Coastal | 554.3 | 555.0 | (0.7 | ) | — | 587.2 | 643.3 | (56.1 | ) | (9 | %) | ||||||||||||||||||||||||||
| Total | 4,684.9 | 4,293.0 | 391.9 | 9 | % | 4,470.3 | 4,398.3 | 72.0 | 2 | % | |||||||||||||||||||||||||||
| NGL production, MBbl/d (4) | |||||||||||||||||||||||||||||||||||||
| Permian Midland (5) | 300.4 | 260.2 | 40.2 | 15 | % | 277.9 | 250.8 | 27.1 | 11 | % | |||||||||||||||||||||||||||
| Permian |
128.1 | 105.3 | 22.8 | 22 | % | 114.1 | 99.1 | 15.0 | 15 | % | |||||||||||||||||||||||||||
| Total Permian | 428.5 | 365.5 | 63.0 | 392.0 | 349.9 | 42.1 | |||||||||||||||||||||||||||||||
| SouthTX (6) | 21.0 | 18.5 | 2.5 | 14 | % | 22.2 | 26.1 | (3.9 | ) | (15 | %) | ||||||||||||||||||||||||||
| 19.7 | 22.1 | (2.4 | ) | (11 | %) | 20.1 | 23.9 | (3.8 | ) | (16 | %) | ||||||||||||||||||||||||||
| SouthOK (6) | 51.5 | 45.9 | 5.6 | 12 | % | 49.5 | 52.4 | (2.9 | ) | (6 | %) | ||||||||||||||||||||||||||
| WestOK | 17.3 | 17.8 | (0.5 | ) | (3 | %) | 16.5 | 20.3 | (3.8 | ) | (19 | %) | |||||||||||||||||||||||||
| Total Central | 109.5 | 104.3 | 5.2 | 108.3 | 122.7 | (14.4 | ) | ||||||||||||||||||||||||||||||
| Badlands (6) | 17.0 | 16.1 | 0.9 | 6 | % | 16.2 | 16.3 | (0.1 | ) | (1 | %) | ||||||||||||||||||||||||||
| Total Field | 555.0 | 485.9 | 69.1 | 516.5 | 488.9 | 27.6 | |||||||||||||||||||||||||||||||
| Coastal | 32.2 | 35.7 | (3.5 | ) | (10 | %) | 33.9 | 40.0 | (6.1 | ) | (15 | %) | |||||||||||||||||||||||||
| Total | 587.2 | 521.6 | 65.6 | 13 | % | 550.4 | 528.9 | 21.5 | 4 | % | |||||||||||||||||||||||||||
| Crude oil, Badlands, MBbl/d | 147.6 | 144.7 | 2.9 | 2 | % | 140.9 | 156.5 | (15.6 | ) | (10 | %) | ||||||||||||||||||||||||||
| Crude oil, Permian, MBbl/d | 34.4 | 37.4 | (3.0 | ) | (8 | %) | 35.0 | 43.3 | (8.3 | ) | (19 | %) | |||||||||||||||||||||||||
| Natural gas sales, BBtu/d (4) | 2,341.8 | 2,140.8 | 201.0 | 9 | % | 2,207.7 | 2,094.8 | 112.9 | 5 | % | |||||||||||||||||||||||||||
| NGL sales, MBbl/d (4) | 424.1 | 380.3 | 43.8 | 12 | % | 394.6 | 399.5 | (4.9 | ) | (1 | %) | ||||||||||||||||||||||||||
| Condensate sales, MBbl/d | 13.9 | 13.6 | 0.3 | 2 | % | 14.9 | 15.5 | (0.6 | ) | (4 | %) | ||||||||||||||||||||||||||
| Average realized prices - inclusive of hedges (8): | |||||||||||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 4.43 | 1.75 | 2.68 | 153 | % | 3.27 | 1.27 | 2.00 | 157 | % | |||||||||||||||||||||||||||
| NGL, $/gal | 0.76 | 0.32 | 0.44 | 138 | % | 0.61 | 0.26 | 0.35 | 135 | % | |||||||||||||||||||||||||||
| Condensate, $/Bbl | 70.29 | 42.37 | 27.92 | 66 | % | 60.02 | 39.40 | 20.62 | 52 | % | |||||||||||||||||||||||||||
| (1) | Beginning in 2021, the Company reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to Targa’s revenue-generating activities and align with the Company’s evaluation of the performance of the business. |
| (2) | 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. |
| (3) | 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. |
| (4) | 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. |
| (5) | Permian Midland includes operations in WestTX, of which the Company owns 72.8%, 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. |
| (6) | Operations include facilities that are not wholly owned by the Company. |
| (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) | 20.2 | $ | (2.51 | ) | $ | (50.8 | ) | 17.5 | $ | (0.15 | ) | $ | (2.6 | ) | ||||||||||
| NGL (MMgal) | 175.8 | (0.31 | ) | (53.9 | ) | 129.3 | 0.03 | 3.6 | ||||||||||||||||
| Crude oil (MBbl) | 0.5 | (23.80 | ) | (11.9 | ) | 0.5 | 15.09 | 7.2 | ||||||||||||||||
| $ | (116.6 | ) | $ | 8.2 | ||||||||||||||||||||
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
| 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) | 76.8 | $ | (1.41 | ) | $ | (108.0 | ) | 68.1 | $ | 0.37 | $ | 25.1 | ||||||||||||
| NGL (MMgal) | 581.5 | (0.26 | ) | (153.1 | ) | 451.4 | 0.12 | 53.3 | ||||||||||||||||
| Crude oil (MBbl) | 2.1 | (14.33 | ) | (30.1 | ) | 1.9 | 18.54 | 34.9 | ||||||||||||||||
| $ | (291.2 | ) | $ | 113.3 | ||||||||||||||||||||
(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 realized commodity prices and higher natural gas inlet volumes resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to higher production and producer activity, and the addition of the Heim plant during the third quarter of 2021. In the Badlands and Coastal regions, natural gas inlet volumes were relatively flat, while in the Central region, the decrease was due to lower production and continued low producer activity.
Operating expenses were higher due to increased activity levels in the Permian and the addition of the Heim plant in the third quarter of 2021, which resulted in increased labor costs, chemicals and materials, partially offset by a reduction in taxes.
Year Ended
The increase in adjusted operating margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in increased margin predominantly in the Permian, partially offset by the short-term operational disruption and impacts associated with a major winter storm during the first quarter of 2021. The increase in natural gas inlet volumes in the Permian was attributable to higher production, higher producer activity, the addition of the Peregrine and
Operating expenses were higher due to increased activity levels in the Permian, the additions of the Peregrine and
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
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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| 2021 | 2020 | 2021 vs. 2020 | 2021 | 2020 | 2021 vs. 2020 | ||||||||||||||||||||||
| (In millions, except operating statistics) | |||||||||||||||||||||||||||
| Operating margin | $ | 343.5 | $ | 322.0 | $ | 21.5 | 7 | % | $ | 1,264.3 | $ | 1,128.0 | $ | 136.3 | 12 | % | |||||||||||
| Operating expenses (1) | 69.2 | 77.2 | (8.0 | ) | (10 | %) | 273.0 | 274.0 | (1.0 | ) | — | ||||||||||||||||
| Adjusted operating margin (1) | $ | 412.7 | $ | 399.2 | $ | 13.5 | 3 | % | $ | 1,537.3 | $ | 1,402.0 | $ | 135.3 | 10 | % | |||||||||||
| Operating statistics MBbl/d (2): | |||||||||||||||||||||||||||
| NGL pipeline transportation volumes (3) | 432.8 | 355.4 | 77.4 | 22 | % | 396.2 | 293.7 | 102.5 | 35 | % | |||||||||||||||||
| Fractionation volumes | 611.6 | 632.3 | (20.7 | ) | (3 | %) | 616.0 | 602.9 | 13.1 | 2 | % | ||||||||||||||||
| Export volumes (4) | 350.3 | 369.5 | (19.2 | ) | (5 | %) | 316.9 | 300.4 | 16.5 | 5 | % | ||||||||||||||||
| NGL sales | 954.9 | 844.4 | 110.5 | 13 | % | 899.7 | 752.5 | 147.2 | 20 | % | |||||||||||||||||
| (1) | Beginning in 2021, the Company reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to Targa’s revenue-generating activities and align with the Company’s evaluation of the performance of the business. |
| (2) | 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. |
| (3) | Represents the total quantity of mixed NGLs that earn a transportation margin. |
| (4) | 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 primarily due to higher pipeline transportation volumes, partially offset by lower fractionation and LPG export volumes and by lower marketing margin. Pipeline transportation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems. Fractionation margin benefited from optimization opportunities, partially offset by slightly lower volumes due to an unplanned outage and associated repairs and maintenance. LPG export volumes were lower due to favorable market conditions in the fourth quarter of 2020 that resulted in a greater number of short-term loadings compared to the fourth quarter of 2021. Marketing margin decreased due to fewer optimization opportunities.
Operating expenses were lower primarily due to the absence of one-time maintenance expenses including hurricane damage repairs in the fourth quarter of 2020.
Year Ended
The increase in adjusted operating margin was primarily due to higher pipeline transportation and fractionation volumes that benefited from higher supply volumes from the Company’s Permian Gathering and Processing systems, partially offset by short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. Additionally, fractionation volumes for the full year were partially offset by an unplanned outage and associated repairs and maintenance in the fourth quarter of 2021. Other drivers included higher marketing margin due to greater optimization opportunities, partially offset by lower LPG export margin primarily attributable to lower fees.
Operating expenses were flat. The sale of assets in
Other
| Three Months Ended |
Year Ended |
|||||||||||||||||||||||
| 2021 | 2020 | 2021 vs. 2020 | 2021 | 2020 | 2021 vs. 2020 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating margin | $ | (60.3 | ) | $ | 13.8 | $ | (74.1 | ) | $ | (115.9 | ) | $ | 229.7 | $ | (345.6 | ) | ||||||||
| Adjusted operating margin | $ | (60.3 | ) | $ | 13.8 | $ | (74.1 | ) | $ | (115.9 | ) | $ | 229.7 | $ | (345.6 | ) | ||||||||
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 400.
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 measure most directly comparable to these non-GAAP measures are income (loss) from operations, net income (loss) attributable to TRC and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within the Company’s industry, the Company’s definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of the Company’s non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes.
Adjusted Operating Margin
The Company defines adjusted operating margin for the Company’s segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.
Gathering and Processing adjusted operating margin consists primarily of:
- service fees related to natural gas and crude oil gathering, treating and processing; and
- revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and the Company’s equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
- service fees (including the pass-through of energy costs included in 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 TRC before interest, income taxes, depreciation and amortization, and other items that the Company believes should be adjusted consistent with the Company’s core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the Company’s financial statements such as investors, commercial banks and others to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support the Company’s indebtedness and pay dividends to the Company’s investors.
Distributable Cash Flow and Adjusted Free Cash Flow
The Company defines distributable cash flow as adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Preferred Units that were issued by the Partnership in
The following table presents a reconciliation of net income (loss) attributable to TRC to adjusted EBITDA, distributable cash flow and adjusted free cash flow for the periods indicated:
| Three Months Ended |
Year Ended |
||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||
| (In millions) | |||||||||||||||
| Reconciliation of Net income (loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow | |||||||||||||||
| Net income (loss) attributable to TRC | $ | (313.6 | ) | $ | 33.6 | $ | 71.2 | $ | (1,553.9 | ) | |||||
| Income attributable to TRP preferred limited partners | — | 6.7 | — | 15.1 | |||||||||||
| Interest (income) expense, net | 103.7 | 98.9 | 387.9 | 391.3 | |||||||||||
| Income tax expense (benefit) | (8.7 | ) | 38.5 | 14.8 | (248.1 | ) | |||||||||
| Depreciation and amortization expense | 219.7 | 217.8 | 870.6 | 865.1 | |||||||||||
| Impairment of long-lived assets | 452.3 | — | 452.3 | 2,442.8 | |||||||||||
| (Gain) loss on sale or disposition of business and assets | 3.7 | 0.4 | 2.0 | 58.4 | |||||||||||
| Write-down of assets | 5.3 | 42.1 | 10.3 | 55.6 | |||||||||||
| (Gain) loss from financing activities (1) | — | 1.8 | 16.6 | (45.6 | ) | ||||||||||
| Equity (earnings) loss | 62.8 | (18.5 | ) | 23.9 | (72.6 | ) | |||||||||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 28.1 | 27.0 | 116.5 | 108.6 | |||||||||||
| Change in contingent considerations | 0.1 | (0.3 | ) | 0.1 | (0.3 | ) | |||||||||
| Compensation on equity grants | 14.6 | 16.7 | 59.2 | 66.2 | |||||||||||
| Risk management activities | 60.4 | (14.0 | ) | 116.0 | (228.2 | ) | |||||||||
| Severance and related benefits (2) | — | — | — | 6.5 | |||||||||||
| Noncontrolling interests adjustments (3) | (57.8 | ) | (12.6 | ) | (89.4 | ) | (224.3 | ) | |||||||
| TRC Adjusted EBITDA | $ | 570.6 | $ | 438.1 | $ | 2,052.0 | $ | 1,636.6 | |||||||
| Distributions to TRP preferred limited partners | — | (6.7 | ) | — | (15.1 | ) | |||||||||
| Interest expense on debt obligations (4) | (90.4 | ) | (99.4 | ) | (376.2 | ) | (388.9 | ) | |||||||
| Maintenance capital expenditures, net (5) | (58.8 | ) | (38.1 | ) | (131.7 | ) | (104.2 | ) | |||||||
| Cash taxes | (0.7 | ) | — | (2.7 | ) | 44.4 | |||||||||
| Distributable Cash Flow | $ | 420.7 | $ | 293.9 | $ | 1,541.4 | $ | 1,172.8 | |||||||
| Growth capital expenditures, net (5) | (179.9 | ) | (79.4 | ) | (407.7 | ) | (597.9 | ) | |||||||
| Adjusted Free Cash Flow | $ | 240.8 | $ | 214.5 | $ | 1,133.7 | $ | 574.9 | |||||||
| (1) | Gains or losses on debt repurchases or early debt extinguishments. |
| (2) | Represents one-time severance and related benefit expense related to the Company’s cost reduction measures. |
| (3) | Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests). |
| (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 TRC to | |||
| Estimated Adjusted EBITDA | |||
| Net income attributable to TRC | $ | 1,260.0 | |
| Interest expense, net | 350.0 | ||
| Income tax expense | 270.0 | ||
| Depreciation and amortization expense | 880.0 | ||
| (Gain) loss on sale of assets | (440.0 | ) | |
| Equity (earnings) loss | — | ||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 45.0 | ||
| Compensation on equity grants | 55.0 | ||
| Noncontrolling interests adjustments (1) | (20.0 | ) | |
| TRC Estimated Adjusted EBITDA | $ | 2,400.0 | |
(1) 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 such as COVID-19, 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.