HOUSTON, Feb. 24, 2022 (GLOBE NEWSWIRE) — Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2021 results.

Fourth Quarter and Full Year 2021 Financial Results

Fourth quarter 2021 net income (loss) attributable to Targa Resources Corp. was $(313.6) million (including a non-cash pre-tax impairment loss of $452.3 million on assets in SouthTX associated with Targa’s Central operations) compared to $33.6 million for the fourth quarter of 2020. For the full year 2021, net income (loss) attributable to Targa Resources Corp. was $71.2 million compared to ($1,553.9) million for 2020. In the first quarter of 2020, the Company recorded a non-cash pre-tax impairment loss of $2,442.8 million for the partial impairment of certain gas processing facilities and gathering systems associated with Targa’s Central operations and full impairment of Targa’s Coastal operations – all of which are in the Gathering and Processing segment.

The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of $570.6 million for the fourth quarter of 2021 compared to $438.1 million for the fourth quarter of 2020. For the full year 2021, Targa reported $2,052.0 million of adjusted EBITDA compared to $1,636.6 million for the full year 2020 (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment), and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”)).

On January 20, 2022, TRC declared a quarterly dividend of $0.35 per share of its common stock for the fourth quarter of 2021, or $1.40 per share on an annualized basis. Total cash dividends of approximately $80 million were paid on February 15, 2022 on all outstanding shares of common stock to holders of record as of the close of business on January 31, 2022. Also, on January 20, 2022, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock (“Series A Preferred”) for the fourth quarter of 2021. Total cash dividends of approximately $22 million were paid on February 14, 2022 on all outstanding shares of Series A Preferred to holders of record as of the close of business on January 31, 2022.

The Company reported distributable cash flow and adjusted free cash flow for the fourth quarter of 2021 of $420.7 million and $240.8 million, respectively. For the full year 2021, the Company reported distributable cash flow and adjusted free cash flow of $1,541.4 million and $1,133.7 million, respectively.

Fourth Quarter 2021 – Sequential Quarter over Quarter Commentary

Targa reported fourth quarter 2021 adjusted EBITDA of $570.6 million, representing a 13 percent increase when compared to the third quarter of 2021. The sequential increase in adjusted EBITDA was primarily attributable to higher realized commodity prices and higher Permian volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems during the fourth quarter. In the G&P segment, higher commodity prices and record Permian natural gas inlet volumes drove the sequential increase in segment adjusted operating margin. The increase in natural gas inlet volumes in the Permian was attributable to an increase in production and activity levels, coupled with a full quarter benefit from Targa’s new Heim plant in Permian Midland which commenced operations late in the third quarter of 2021. In the L&T segment, higher sequential pipeline transportation and LPG export volumes, coupled with higher fractionation and marketing margin drove the sequential increase in segment adjusted operating margin. Targa’s Grand Prix NGL Pipeline (“Grand Prix”) operated at record levels during the fourth quarter primarily due to higher supply volumes from Targa’s Permian G&P systems. Fractionation margin benefited from optimization opportunities, partially offset by lower fractionation volumes due to an unplanned outage and associated repairs and maintenance during the fourth quarter. Marketing margin was higher sequentially due to greater optimization opportunities. Higher sequential operating and G&A expenses were attributable to higher compensation expense and increased activity levels, partially offset by lower ad valorem expense.

Capitalization and Liquidity

The Company’s total consolidated debt as of December 31, 2021 was $6,597.2 million, net of $45.0 million of debt issuance costs, with $150.0 million outstanding under Targa Resources Partners LP’s (“TRP” or the “Partnership”) accounts receivable securitization facility (the “Securitization Facility”), $6,465.7 million of outstanding TRP senior notes and $26.5 million of finance lease liabilities.

Total consolidated liquidity as of December 31, 2021, was over $3.2 billion, including $158.5 million of cash and $250.0 million available under the Securitization Facility. As of December 31, 2021, TRC had no borrowings under its $670.0 million senior secured revolving credit facility (the “Existing TRC Revolver”), and TRP had no borrowings and had $71.3 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility (the “Existing TRP Revolver”), resulting in available senior secured revolving credit facility capacity of $2,128.7 million.

Financing Update

In February 2022, Targa entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto (the “New TRC Revolver”). The New TRC Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion and matures on February 17, 2027. In connection with the entry into the New TRC Revolver, Targa terminated the Existing TRC Revolver and the Existing TRP Revolver.

Common Share Repurchases

In the fourth quarter of 2021, Targa repurchased 756,478 shares of its common stock at a weighted average price of $52.81 for a total net cost of approximately $40 million. There was approximately $369 million remaining under its $500 million authorized common share repurchase program as of December 31, 2021.

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 Sand Hills plant (which is expected to be idled when Midway is operational) in addition to providing incremental processing capacity. The Midway plant is expected to enhance Targa’s operational performance and flexibility, and reduce operating expenses and maintenance capital expenditures. The Midway plant is expected to begin operations in the third quarter of 2023.

2022 Operational and Financial Expectations

Targa’s operational and financial expectations assume natural gas liquids (“NGL”) composite barrel prices average $0.85 per gallon, crude oil prices average $75 per barrel and Waha natural gas prices average $3.75 per million British Thermal Units (“MMbtu”) for 2022. Targa estimates 2022 average Permian natural gas inlet volumes will increase 12 percent to 15 percent over its 2021 average Permian natural gas inlet volumes, which is expected to drive incremental volumes through its L&T systems.

For 2022, Targa estimates full year adjusted EBITDA to be between $2.3 billion and $2.5 billion, with the midpoint of the range representing a 17 percent increase over full year 2021 adjusted EBITDA. Targa’s full year 2022 adjusted EBITDA estimate is pro forma for the sale of its 25 percent equity interest in the Gulf Coast Express Pipeline. Targa’s estimate for 2022 net growth capital expenditures is between $700 million to $800 million, based on announced projects and other identified spending, including the Legacy II and Midway plants in its Permian region. Net maintenance capital expenditures for 2022 are estimated to be approximately $150 million. Please see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of forward-looking estimated adjusted EBITDA and a reconciliation of such measure to its most directly comparable GAAP financial measure.

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 11:00 a.m. Eastern time (10:00 a.m. Central time) on February 24, 2022 to discuss its fourth quarter results. The conference call can be accessed via webcast under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events, or by going directly to https://edge.media-server.com/mmc/p/r843intk. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

Targa Resources Corp. – Consolidated Financial Results of Operations

Three Months Ended December 31, Year Ended December 31,
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 Targa Resources Corp. (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 December 31, 2021 Compared to Three Months Ended December 31, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($2,626.4 million) and higher NGL and natural gas volumes ($249.1 million), partially offset by the unfavorable impact of hedges ($121.5 million).

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 $452.3 million on assets in SouthTX associated with the Company’s Central operations.

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 $77.2 million on the Company’s investments in T2 Eagle Ford and T2 LaSalle located in SouthTX in 2021.

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 December 31, 2021 Compared to Year Ended December 31, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($8,449.3 million) and higher NGL and natural gas volumes ($917.3 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($147.6 million) and the unfavorable impact of hedges ($787.5 million).

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 $452.3 million on assets in SouthTX associated with the Company’s Central operations. In 2020, the Company recognized a non-cash pre-tax impairment loss of $2,442.8 million on assets in the Mid-Continent region associated with the Company’s Central operations and full impairment of the Company’s Coastal operations.

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 Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.

The decrease in equity earnings is primarily due to non-cash pre-tax impairment losses of $77.2 on the Company’s investments in T2 Eagle Ford and T2 LaSalle located in SouthTX and lower earnings from the Company’s investments in Gulf Coast Fractionators LP, Cayenne Pipeline, LLC and GCX DevCo JV.

During 2021, the Partnership redeemed the 5⅛% Notes and the 4¼% Notes and Targa Pipeline Partners LP (“TPL”) redeemed the TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023, resulting in a $16.6 million net loss from financing activities. During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024 and the 5¼% Senior Notes due 2023, resulting in a $45.6 million net gain from financing activities.

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 December 2020.

The decrease in dividends on Series A Preferred is due to the partial repurchase of the Company’s Series A Preferred in December 2020.

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.

GLJ

Review of Segment Performance

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and adjusted operating margin as important performance measures of the core profitability of its operations. These measures are key components of internal financial reporting and are reviewed for consistency and trend analysis. For a discussion of adjusted operating margin, see “Non-GAAP Financial Measures ― Adjusted Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation.

The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Transportation.

Gathering and Processing Segment

The Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

Three Months Ended December 31, Year Ended December 31,
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 Delaware 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 %)
North Texas 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 Delaware 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 %)
North Texas 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 December 31, 2021 Three Months Ended December 31, 2020
(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 December 31, 2021 Year Ended December 31, 2020
(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 December 31, 2021 Compared to Three Months Ended December 31, 2020

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 December 31, 2021 Compared to Year Ended December 31, 2020

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 Gateway plants during 2020 and the Heim plant during the third quarter of 2021. In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal regions was due to lower production and continued low producer activity. Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian, the additions of the Peregrine and Gateway plants in 2020 and the Heim plant in the third quarter of 2021, which resulted in increased labor costs, materials and chemicals, partially offset by a reduction in taxes.

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, which connects the Company’s gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company’s Downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by the Company’s Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

Three Months Ended December 31, Year Ended December 31,
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 Galena Park Marine Terminal that are destined for international markets.

Three Months Ended December 31, 2021 Compared to Three Months Ended December 31, 2020

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 December 30, 2021 Compared to Year Ended December 31, 2020

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 Channelview, Texas in 2020 and the absence of one-time maintenance expenses, including hurricane damage repairs in the fourth quarter of 2020, were offset by higher taxes due to system expansions and higher compensation and benefits.

Other

Three Months Ended December 31, Year Ended December 31,
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 Resources Corp.

Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary midstream infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company’s assets connect natural gas and NGLs to domestic and international markets with growing demand for cleaner fuels and feedstocks. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas; transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling, and purchasing and selling crude oil.

Targa is a FORTUNE 500 company and is included in the S&P 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 October 2015 were redeemed in December 2020. 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 TRC to adjusted EBITDA, distributable cash flow and adjusted free cash flow for the periods indicated:

Three Months Ended December 31, Year Ended December 31,
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 Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, the timing and success of business development efforts, and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its most recent Annual Report on Form 10-K, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Contact the Company’s investor relations department by email at [email protected] or by phone at (713) 584-1133.

Sanjay Lad
Vice President, Finance & Investor Relations

Jennifer Kneale
Chief Financial Officer