Targa Resources Corp. Reports Fourth Quarter and Full Year 2020 Financial Results and Provides 2021 Operational and Financial Outlook

HOUSTON, Feb. 18, 2021 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2020 results.

Fourth Quarter and Full Year 2020 Financial Results

Fourth quarter 2020 net income (loss) attributable to Targa Resources Corp. was $33.6 million compared to ($112.8) million for the fourth quarter of 2019. In the fourth quarter of 2019, the Company recorded a non-cash pre-tax impairment charge of $225.3 million for the partial impairment of certain gas processing facilities and gathering systems associated with Targa’s Central and Coastal operations. For the full year 2020, net income (loss) attributable to Targa was ($1,553.9) million compared to ($209.2) million for 2019. In 2020, the Company recorded a non-cash pre-tax impairment charge 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 $438.1 million for the fourth quarter of 2020 compared to $465.2 million for the fourth quarter of 2019 and $1,636.6 million for the full year 2020 compared to $1,435.5 million for the full year 2019 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, free cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

On January 20, 2021, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended December 31, 2020, or $0.40 per share on an annualized basis. Total cash dividends of approximately $22.9 million were paid on February 16, 2021 on all outstanding shares of common stock to holders of record as of the close of business on February 1, 2021. Also on January 20, 2021, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million were paid on February 12, 2021 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on February 1, 2021.

The Company reported distributable cash flow and free cash flow before dividends for the fourth quarter of 2020 of $293.9 million and $214.5 million. For the full year 2020, the Company reported distributable cash flow and free cash flow before dividends of $1,172.8 million and $574.9 million, respectively.

Fourth Quarter 2020 - Sequential Quarter over Quarter Commentary

Targa reported fourth quarter 2020 Adjusted EBITDA of $438.1 million, representing a 5 percent increase over the third quarter. The sequential increase in Adjusted EBITDA was predominantly attributable to full quarter contributions from projects that began operations during the third quarter, combined with strong operational performance across Targa’s Logistics and Transportation (“L&T”) systems, partially offset by higher operating expenses. In the Gathering and Processing (“G&P”) segment, the sequential increase in segment gross margin was partially attributable to higher Permian natural gas inlet volumes and higher Permian fee-based margin. In the L&T segment, the sequential increase in gross margin was primarily attributable to strong Grand Prix NGL Pipeline (“Grand Prix”) transportation throughput, and higher fractionation and liquefied petroleum gas (“LPG”) export volumes, combined with higher marketing margin. Fourth quarter Grand Prix volumes increased 18 percent sequentially, driven by incremental NGL volumes from Targa’s Permian plants, including the new Gateway Plant in Permian Midland which began operations during the third quarter. Targa’s LPG export volumes achieved a record 11.3 million barrels per month during the quarter, increasing 20 percent over the third quarter and benefited from a full quarter of the phased expansion completed in the third quarter. Fourth quarter fractionation volumes benefited from higher Permian volumes, in addition to inventory as a result of the scheduled maintenance performed during the third quarter, which shifted the timing of incremental volumes to be fractionated to the fourth quarter. Higher sequential operating expenses were attributable to recently completed system expansions and certain one-time maintenance expenses including hurricane damage repairs and integrity spending during the fourth quarter, while higher general and administrative expenses were largely attributable to compensation and legal costs.

Capitalization and Liquidity

The Company’s total consolidated debt as of December 31, 2020 was $7,755.7 million including $555.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,200.7 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $45.5 million of debt issuance costs, with $280.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $350.0 million outstanding under TRP’s accounts receivable securitization facility, $6,585.4 million of outstanding TRP senior notes, net of unamortized premiums, and $30.8 million of finance lease liabilities.

Total consolidated liquidity as of December 31, 2020, was over $2.2 billion and included $242.8 million of cash. As of December 31, 2020, TRC had available borrowing capacity under its senior secured revolving credit facility of $115.0 million. TRP had $280.0 million of borrowings and $44.4 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $1,875.6 million.

Financing Update

In November 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023 with available liquidity under the Partnership’s senior secured revolving credit facility (the “TRP Revolver”). The Company recorded a loss due to debt extinguishment of $1.8 million comprised of a write-off of debt issuance costs.

In December 2020, the Partnership redeemed all of its 5,000,000 issued and outstanding 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) at a redemption price of $25.00 per unit, plus an amount equal to all unpaid distributions up to the date of redemption. The redemption of the Preferred Units is consistent with the Company’s ongoing efforts to simplify the Company’s capital structure and to identify opportunities to generate additional cash flow by enabling the Company to realize annual cash savings associated with the elimination of Preferred Unit distributions.

In December 2020, Targa repurchased 45,800 shares of the Company’s Series A Preferred Stock at $1,000 per share (the “Liquidation Preference”), plus an amount equal to all unpaid dividends through the repurchase date. The repurchase was executed at a discount relative to the redemption price of $1,100 per share (the Liquidation Preference multiplied by 110%), which becomes effective March 16, 2021. The partial repurchase is consistent with Targa’s ongoing efforts to opportunistically simplify the Company’s capital structure and to identify opportunities to generate additional cash flow by enabling the Company to realize annual cash savings associated with the reduction of preferred stock dividends.

In February 2021, the Partnership issued $1.0 billion of 4% Senior Notes due 2032, resulting in net proceeds of approximately $992 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025, with the remainder used for repayment of borrowings under the TRP Revolver and the Company’s senior secured revolving credit facility. Additionally, Targa Pipeline Partners LP (“TPL”) issued notices of redemption for all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023. These notes will be redeemed on February 22, 2021 with available liquidity under the TRP Revolver.

Share Repurchase Update

In October 2020, the Company’s Board of Directors approved a share repurchase program (the “Share Repurchase Program”) for the repurchase of up to $500 million of the Company’s outstanding common stock. As of February 12, 2021, the Company has repurchased 5,485,874 shares at a weighted average price of $16.68 for a total net cost of $91.5 million. There is approximately $408.5 million remaining under the Share Repurchase Program.

2021 Operational and Financial Expectations

The 2021 operational and financial expectations presented herein were developed in advance of the impacts of the severe winter weather currently being experienced across Targa’s operations. Both G&P and L&T operations have been affected and the impacts are being evaluated.

Targa estimates 2021 average Permian natural gas inlet volumes will increase 5 percent to 10 percent over its 2020 average Permian natural gas inlet volumes. Targa estimates 2021 average total Field Gathering and Processing natural gas inlet volumes will be flat over the 2020 average. In its L&T segment, Targa estimates average Grand Prix volume deliveries into Mont Belvieu to increase 25 percent or more over 2020.

For 2021, Targa estimates full year Adjusted EBITDA to be between $1,675 million and $1,775 million, with the midpoint of the range representing a 5 percent increase over full year 2020 Adjusted EBITDA. Targa’s full year Adjusted EBITDA outlook assumes natural gas liquids (“NGL”) composite barrel prices average $0.55 per gallon, crude oil prices average $50 per barrel and Henry Hub and Waha natural gas prices average $3.00 and $2.65 per million British Thermal Units (“MMBtu”) for the year. Targa expects approximately 85 percent of its margin to be fee-based in 2021. Targa’s estimate for 2021 net growth capital expenditures is between $350 million to $450 million, based on announced projects and other identified spending, with the midpoint of the range representing a 33 percent decrease over full year 2020 net growth capital expenditures. Net maintenance capital expenditures for 2021 are estimated to be approximately $130 million.

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 12:00 p.m. Eastern time (11:00 a.m. Central time) on February 23, 2021 to discuss fourth quarter and full year 2020 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/ch8ddv3n. 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,        
 2020  2019  2020 vs. 2019  2020  2019  2020 vs. 2019 
 (In millions) 
Revenues:                             
Sales of commodities$2,270.2  $2,139.1  $131.1  6% $7,171.0  $7,393.8  $(222.8) (3%)
Fees from midstream services 302.6   334.8   (32.2) (10%)  1,089.3   1,277.3   (188.0) (15%)
Total revenues 2,572.8   2,473.9   98.9  4%  8,260.3   8,671.1   (410.8) (5%)
Product purchases 1,758.3   1,702.8   55.5  3%  5,105.1   6,118.5   (1,013.4) (17%)
Gross margin (1) 814.5   771.1   43.4  6%  3,155.2   2,552.6   602.6  24%
Operating expenses 214.7   192.1   22.6  12%  779.8   792.9   (13.1) (2%)
Operating margin (1) 599.8   579.0   20.8  4%  2,375.4   1,759.7   615.7  35%
Depreciation and amortization expense 217.8   252.7   (34.9) (14%)  865.1   971.6   (106.5) (11%)
General and administrative expense 74.0   57.2   16.8  29%  254.6   280.7   (26.1) (9%)
Impairment of long-lived assets    225.3   (225.3) (100%)  2,442.8   225.3   2,217.5 NM 
Other operating (income) expense 42.8   67.5   (24.7) (37%)  116.6   89.2   27.4  31%
Income (loss) from operations 265.2   (23.7)  288.9 NM   (1,303.7)  192.9   (1,496.6)NM 
Interest expense, net (98.9)  (96.0)  (2.9) 3%  (391.3)  (337.8)  (53.5) 16%
Equity earnings (loss) 18.5   23.1   (4.6) (20%)  72.6   39.0   33.6  86%
Gain (loss) from financing activities (1.8)     (1.8)    45.6   (1.4)  47.0 NM 
Gain (loss) from sale of equity-method investment    3.5   (3.5) (100%)     69.3   (69.3) (100%)
Change in contingent considerations 0.3      0.3     0.3   (8.7)  9.0  103%
Other, net 1.2   0.1   1.1 NM   3.4      3.4   
Income tax (expense) benefit (38.5)  77.9   (116.4) (149%)  248.1   87.9   160.2  182%
Net income (loss) 146.0   (15.1)  161.1 NM   (1,325.0)  41.2   (1,366.2)NM 
Less: Net income (loss) attributable to noncontrolling interests 112.4   97.7   14.7  15%  228.9   250.4   (21.5) (9%)
Net income (loss) attributable to Targa Resources Corp. 33.6   (112.8)  146.4  130%  (1,553.9)  (209.2)  (1,344.7)NM 
Dividends on Series A Preferred Stock 22.9   22.9        91.7   91.7      
Deemed dividends on Series A Preferred Stock 11.5   8.7   2.8  32%  39.2   33.1   6.1  18%
Net income (loss) attributable to common shareholders$(0.8) $(144.4) $143.6  99% $(1,684.8) $(334.0) $(1,350.8)NM 
Financial data:                             
Adjusted EBITDA (1)$438.1  $465.2  $(27.1) (6%) $1,636.6  $1,435.5  $201.1  14%
Distributable cash flow (1) 293.9   327.8   (33.9) (10%)  1,172.8   947.2   225.6  24%
Free cash flow (1) 214.5   (7.7)  222.2 NM   574.9   (1,334.5)  1,909.4 NM 

(1)   Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
NM   Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended December 31, 2020 Compared to Three Months Ended December 31, 2019

The increase in sales of commodities reflects higher natural gas liquid (“NGL”) and natural gas volumes ($201.7 million) and higher NGL and natural gas prices ($193.9 million), partially offset by lower crude marketing, petroleum products, and condensate volumes ($196.2 million), lower condensate prices ($23.9 million) and the unfavorable impact of hedges ($44.0 million).

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, lower gas processing volumes and lower transportation fees, partially offset by increased export and pipeline transport volumes.

The increase in product purchases reflects higher NGL and natural gas volumes and prices, partially offset by lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower petroleum products and condensate volumes.

Higher operating margin and gross margin in 2020 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by depreciation related to major growth capital projects placed in service, including Train 7 in the first quarter of 2020 and the additional processing plants and associated infrastructure in the Permian Basin.

General and administrative expense increased primarily due to higher compensation and benefits and an increase in insurance costs.

The Company recognized a non-cash pre-tax impairment charge of $225.3 million in 2019 primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with Targa’s Central and Coastal operations.

Other operating (income) expense in 2020 consisted primarily of write-downs of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s Delaware crude system, which was effective December 1, 2019, and write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The decrease in equity earnings is primarily due to lower earnings from the Company’s investments in Gulf Coast Fractionators LP (“GCF”) and Gulf Coast Express Pipeline LLC (“GCX”).

During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 5¼% Senior Notes due 2023, resulting in a $1.8 million loss from financing activities.

During 2019, the Company closed on the sale of an equity-method investment that resulted in a gain during the fourth quarter of $3.5 million.

The increase in income tax expense is primarily due to differences in pre-tax book income (loss) and a valuation allowance in 2020.

Net income attributable to noncontrolling interests was higher in 2020 primarily due to increased earnings allocated to interests holders in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), Grand Prix Development LLC (“Grand Prix DevCo Joint Venture”) and Carnero G&P LLC.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

The decrease in sales of commodities reflects lower NGL, condensate, petroleum product and natural gas prices ($945.1 million) and lower crude marketing and petroleum product volumes ($397.1 million), partially offset by higher NGL, natural gas, and condensate volumes ($816.3 million) and the favorable impact of hedges ($301.1 million).

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, partially offset by increased export and terminaling and storage volumes.

The decrease in product purchases reflects lower NGL, condensate, petroleum product and natural gas prices, lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower petroleum products volumes, partially offset by higher NGL, natural gas and condensate volumes.

Higher operating margin and gross margin in 2020 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by depreciation related to major growth capital projects placed in service, including Train 7 in the first quarter of 2020, the additional processing plants and associated infrastructure in the Permian Basin and a full year of depreciation related to Grand Prix, which was placed in service in the third quarter of 2019.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.

The Company recognized non-cash pre-tax impairment charges of $2,442.8 million and $225.3 million during 2020 and 2019. The non-cash pre-tax impairment charge in 2020 is primarily associated with 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. The non-cash pre-tax impairment charge in 2019 is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with Targa’s Central and Coastal operations.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the sale of the Company’s assets in Channelview, Texas and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s Delaware crude system, which was effective December 1, 2019, and write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from the Company’s investments in GCX and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from GCF.

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. During 2019, the Partnership redeemed the 4⅛% Senior Notes due 2019, resulting in $1.4 million loss from financing activities.

During 2019, the Partnership closed on the sale of an equity-method investment that resulted in a gain of $69.3 million.

The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act, partially offset by a valuation allowance in 2020.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of non-cash pre-tax impairment losses recognized during the first quarter of 2020, partially offset by increased earnings allocated to interests holders in the three development joint ventures with investment vehicles affiliated with Stonepeak Infrastructure Partners to fund portions of Grand Prix pipeline, Gulf Coast Express Pipeline and a fractionator in Mont Belvieu, Texas, Targa Badlands LLC and Grand Prix Joint Venture.

Review of Segment Performance

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and gross 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 operating margin and gross margin, see “Targa Resources Corp. ― Non-GAAP Financial Measures ― Operating Margin” and “Targa Resources Corp. ― Non-GAAP Financial Measures ― Gross 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, 
  2020  2019  2020 vs. 2019  2020  2019  2020 vs. 2019 
  (In millions, except operating statistics and price amounts) 
Gross margin $378.6  $403.9  $(25.3) (6%) $1,450.3  $1,496.0  $(45.7) (3%)
Operating expenses  114.7   114.2   0.5  0  432.6   489.6   (57.0) (12%)
Operating margin $263.9  $289.7  $(25.8) (9%) $1,017.7  $1,006.4  $11.3  1%
Operating statistics (1):                              
Plant natural gas inlet, MMcf/d (2),(3)                              
Permian Midland (4)  1,815.4   1,621.0   194.4  12%  1,745.6   1,471.6   274.0  19%
Permian Delaware  779.8   740.7   39.1  5%  729.4   599.7   129.7  22%
Total Permian  2,595.2   2,361.7   233.5      2,475.0   2,071.3   403.7    
                               
SouthTX (5)  208.0   279.4   (71.4) (26%)  248.1   321.2   (73.1) (23%)
North Texas  187.4   224.9   (37.5) (17%)  201.6   226.9   (25.3) (11%)
SouthOK (6)  382.4   606.1   (223.7) (37%)  443.0   606.1   (163.1) (27%)
WestOK  222.2   315.3   (93.1) (30%)  249.5   330.2   (80.7) (24%)
Total Central  1,000.0   1,425.7   (425.7)     1,142.2   1,484.4   (342.2)   
                               
Badlands (7),(8)  142.8   156.2   (13.4) (9%)  137.8   116.7   21.1  18%
Total Field  3,738.0   3,943.6   (205.6)     3,755.0   3,672.4   82.6    
                               
Coastal  555.0   757.6   (202.6) (27%)  643.3   774.2   (130.9) (17%)
                               
Total  4,293.0   4,701.2   (408.2) (9%)  4,398.3   4,446.6   (48.3) (1%)
NGL production, MBbl/d (3)                              
Permian Midland (4)  260.2   236.7   23.5  10%  250.8   209.1   41.7  20%
Permian Delaware  105.3   99.7   5.6  6%  99.1   78.6   20.5  26%
Total Permian  365.5   336.4   29.1      349.9   287.7   62.2    
                               
SouthTX (5)  18.5   34.4   (15.9) (46%)  26.1   41.6   (15.5) (37%)
North Texas  22.1   26.3   (4.2) (16%)  23.9   26.8   (2.9) (11%)
SouthOK (6)  45.9   72.1   (26.2) (36%)  52.4   67.1   (14.7) (22%)
WestOK  17.8   19.3   (1.5) (8%)  20.3   21.6   (1.3) (6%)
Total Central  104.3   152.1   (47.8)     122.7   157.1   (34.4)   
                               
Badlands (8)  16.1   18.3   (2.2) (12%)  16.3   13.8   2.5  18%
Total Field  485.9   506.8   (20.9)     488.9   458.6   30.3    
                               
Coastal  35.7   46.1   (10.4) (23%)  40.0   46.8   (6.8) (15%)
                               
Total  521.6   552.9   (31.3) (6%)  528.9   505.4   23.5  5%
Crude oil, Badlands, MBbl/d  144.7   189.0   (44.3) (23%)  156.5   172.6   (16.1) (9%)
Crude oil, Permian, MBbl/d (9)  37.4   74.9   (37.5) (50%)  43.3   83.3   (40.0) (48%)
Natural gas sales, BBtu/d (3),(10)  2,140.8   2,048.6   92.2  5%  2,094.8   2,020.6   74.2  4%
NGL sales, MBbl/d (3),(10)  380.3   420.1   (39.8) (9%)  399.5   391.9   7.6  2%
Condensate sales, MBbl/d  13.6   12.4   1.2  10%  15.5   12.3   3.2  26%
Average realized prices - inclusive of hedges (11):                              
Natural gas, $/MMBtu  1.75   1.48   0.27  18%  1.27   1.35   (0.08) (6%)
NGL, $/gal  0.32   0.32        0.26   0.34   (0.08) (24%)
Condensate, $/Bbl  42.37   51.44   (9.07) (18%)  39.40   49.99   (10.59) (21%)

(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 year and the denominator is the number of calendar days during the year.
(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%, 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)   SouthTX includes the Raptor Plant, of which the Company owns a 50% interest through the Carnero Joint Venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(6)   SouthOK includes the Centrahoma Joint Venture, of which the Company owns 60%, and other plants that are owned 100% by the Company. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(7)   Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 Plant.
(8)   As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which the Company owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(9)   Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019.
(10)   Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to the Company’s operating or gross margin.
(11)   Average realized prices include the effect of realized commodity hedge gain/loss attributable to the Company’s equity volumes, previously shown in Other. 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 gross margin of Gathering and Processing segment:

  Three Months Ended December 31, 2020  Three Months Ended December 31, 2019 
  (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)  17.5  $(0.15) $(2.6)  15.9  $0.83  $13.1 
NGL (MMgal)  129.3   0.03   3.6   117.6   0.09   10.1 
Crude oil (MBbl)  0.5   15.09   7.2   0.4   (2.10)  (0.9)
          $8.2          $22.3 
                         
  Year Ended December 31, 2020  Year Ended December 31, 2019 
  (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)  68.1  $0.37  $25.1   62.9  $1.17  $73.7 
NGL (MMgal)  451.4   0.12   53.3   369.7   0.10   38.0 
Crude oil (MBbl)  1.9   18.54   34.9   1.5   (2.29)  (3.5)
          $113.3          $108.2 

(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, 2020 Compared to Three Months Ended December 31, 2019

The decrease in Gathering and Processing segment gross margin was primarily due to lower volumes in the Central region and the Badlands and lower realized hedge gains, partially offset by higher system volumes and fee-based margin in the Permian region. Lower volumes in the Central region and the Badlands were attributable to reduced producer activity and continued producer shut-ins. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Peregrine and Gateway plants in 2020. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the fourth quarter of 2020, which necessitated temporary shut downs of certain facilities. Total crude oil volumes decreased in the Badlands due to reduced producer activity, while the decrease in the Permian was primarily due to the sale of the Delaware Crude System in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures implemented in response to the impact of the COVID-19 pandemic on the Company’s business, which resulted in decreases in compensation and benefits, chemicals and contract labor, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

During the year ended December 31, 2020, the COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weak commodity prices compared to historical levels and price volatility. The drop in commodity prices also resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production, particularly during the second quarter.

The resulting decrease in Gathering and Processing segment gross margin was primarily due to lower Central region volumes and lower commodity prices, partially offset by higher inlet volumes and fee-based margin in the Permian region and the Badlands and higher realized hedge gains. Lower volumes in the Central region were attributable to reduced producer activity and temporary shut-ins. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third and fourth quarters of 2020, which necessitated temporary shut downs of certain facilities. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures implemented in response to the impact of the COVID-19 pandemic on the Company’s business, which resulted in decreases in contract labor, chemicals and compressor rentals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

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 liquefied petroleum gas 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, as well as the Company’s equity interest in GCX, a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of the Company’s Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points. The associated assets, including these pipelines, 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,          
  2020  2019  2020 vs. 2019   2020   2019  2020 vs. 2019 
 (In millions, except operating statistics and price amounts) 
Gross margin $ 423.7  $ 381.2  $ 42.5   11% $ 1,480.7  $ 1,173.9  $ 306.8   26%
Operating expenses (1)   101.7    79.2    22.5   28%   352.7    306.7    46.0   15%
Operating margin $ 322.0  $ 302.0  $ 20.0   7% $ 1,128.0  $ 867.2  $ 260.8   30%
Operating statistics MBbl/d (2):                                      
Fractionation volumes (3)   632.3    596.7    35.6   6%   602.9    519.0    83.9   16%
Export volumes (4)   369.5    267.1    102.4   38%   300.4    237.9    62.5   26%
Pipeline throughput (5)   355.4    266.4    89.0   33%   293.7    100.4    193.3  NM 
NGL sales   844.4    740.3    104.1   14%   752.5    651.0    101.5   16%

(1)   Effective January 1, 2020, pursuant to amendments to contractual arrangements with the Company’s partners, the Company’s share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses.
(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 year and the denominator is the number of calendar days during the year.
(3)   Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy. As such, the Logistics and Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses.
(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.
(5)   Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.
NM   Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended December 31, 2020 Compared to Three Months Ended December 31, 2019

The increase in Logistics and Transportation segment gross margin was driven by higher pipeline transportation, fractionation and LPG export system volumes from higher supply volumes from the Company’s Permian Gathering and Processing systems and associated downstream system expansions, partially offset by fewer optimization opportunities in the Company’s marketing businesses. NGL transportation and fractionation volumes increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and the commencement of operations of Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020.

Operating expenses were higher due to system expansions, including Grand Prix, fractionation capacity and expansion of the Company’s LPG export capabilities, certain one-time maintenance expenses including hurricane damage repairs, higher fuel and power costs, and the Company’s share of operating expenses associated with GCF, partially offset by cost reduction measures.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

The increase in Logistics and Transportation segment gross margin was driven by higher pipeline transportation, fractionation and LPG export system volumes from higher supply volumes from the Company’s Permian Gathering and Processing systems and associated downstream system expansions, partially offset by fewer optimization opportunities in the Company’s marketing businesses. NGL transportation and fractionation volumes increased due to higher volumes delivered on Grand Prix and the commencement of operations of Train 6 in the second quarter of 2019, Train 7 and Train 8.

Operating expenses were higher due to system expansions, including Grand Prix, fractionation capacity and expansion of the Company’s LPG export capabilities and the Company’s share of operating expenses associated with GCF and certain one-time maintenance expenses including hurricane damage repairs, partially offset by lower fuel and power costs and cost reduction measures.

Other

  Three Months Ended December 31,      Year Ended December 31,     
  2020  2019  2020 vs. 2019  2020  2019  2020 vs. 2019 
  (In millions) 
Gross margin $13.8  $(12.7) $26.5  $229.7  $(113.9) $343.6 
Operating margin $13.8  $(12.7) $26.5  $229.7  $(113.9) $343.6 

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. 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.

For more information, please visit the Company’s website at www.targaresources.com.

Targa Resources Corp. - Non-GAAP Financial Measures

This press release includes the Company’s non-GAAP financial measures: Adjusted EBITDA, distributable cash flow, free cash flow, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. These non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance.

The Company utilizes non-GAAP measures to analyze the Company’s performance. Gross margin, operating margin, Adjusted EBITDA, distributable cash flow, and free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRC 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 net income, 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 EBITDA

Adjusted EBITDA is defined 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 Free Cash Flow

Distributable cash flow is defined 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 issued by the Partnership in October 2015 were redeemed in December 2020 and are no longer outstanding as of the end of the year. Free cash flow is defined 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 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 attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow for the periods indicated:

  Three Months Ended December 31,  Year Ended December 31, 
  2020  2019  2020  2019 
  (In millions) 
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow                    
Net income (loss) attributable to TRC $ 33.6  $ (112.8) $ (1,553.9) $ (209.2)
Income attributable to TRP preferred limited partners   6.7    2.9    15.1    11.3 
Interest (income) expense, net   98.9    96.0    391.3    337.8 
Income tax expense (benefit)   38.5    (77.9)   (248.1)   (87.9)
Depreciation and amortization expense   217.8    252.7    865.1    971.6 
Impairment of long-lived assets       225.3    2,442.8    225.3 
(Gain) loss on sale or disposition of business and assets   0.4    63.8    58.4    71.1 
Write-down of assets   42.1    3.7    55.6    17.9 
(Gain) loss from sale of equity-method investment       (3.5)       (69.3)
(Gain) loss from financing activities (1)   1.8        (45.6)   1.4 
Equity (earnings) loss   (18.5)   (23.1)   (72.6)   (39.0)
Distributions from unconsolidated affiliates and preferred partner interests, net   27.0    27.8    108.6    61.2 
Change in contingent considerations   (0.3)   (0.1)   (0.3)  8.7 
Compensation on equity grants   16.7    11.3    66.2    60.3 
Risk management activities   (14.0)   12.0    (228.2)   112.8 
Severance and related benefits (2)           6.5     
Noncontrolling interests adjustments (3)   (12.6)   (12.9)   (224.3)   (38.5)
TRC Adjusted EBITDA $ 438.1  $ 465.2  $ 1,636.6   $ 1,435.5 
Distributions to TRP preferred limited partners   (6.7)   (2.9)   (15.1)   (11.3)
Interest expense on debt obligations (4)   (99.4)   (95.1)   (388.9)   (342.1)
Cash tax refund           44.4     
Maintenance capital expenditures   (41.8)   (40.2)   (109.5)   (141.7)
Noncontrolling interests adjustments of maintenance capital expenditures   3.7    0.8    5.3    6.8 
Distributable Cash Flow $ 293.9  $ 327.8  $ 1,172.8   $ 947.2 
Growth capital expenditures, net (5)   (79.4)   (335.5)   (597.9)   (2,281.7)
Free Cash Flow $ 214.5  $ (7.7) $ 574.9   $ (1,334.5)

(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 growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.

The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow. The following table details construction and project completion timing of the Company’s announced major growth capital projects:

  Three Months Ended
  March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 March 31, 2020 June 30, 2020 September 30, 2020 December 31, 2020
Major Growth Capital Project (1):                
Gathering & Processing:                
Hopson Plant (2) UC C            
Falcon Plant (3) UC UC C          
Pembrook Plant (2) UC UC C          
Little Missouri 4 Plant (4) UC UC C          
Peregrine Plant (3) UC UC UC UC UC C    
Gateway Plant (2)     UC UC UC UC C  
Heim Plant (5)               UC
                 
Logistics & Transportation:                
Train 6 UC C            
Grand Prix NGL Pipeline UC UC C          
Gulf Coast Express Pipeline UC UC C          
Train 7 UC UC UC UC C      
Train 8 UC UC UC UC UC UC C  
LPG Export Expansion UC UC UC UC UC UC C  
Grand Prix Central OK Extension UC UC UC UC UC UC UC C

(1)   “UC” and “C” indicates under construction and project completed, respectively, as of the end of the period presented above.
(2)   Part of the Company’s Permian Midland operating area.
(3)   Part of the Company’s Permian Delaware operating area.
(4)   Part of the Company’s Badlands operating area.
(5)   In November 2020, the Company announced the relocation of the former Longhorn Plant from the Company’s North Texas system to the Company’s Permian Midland system as the Heim Plant. The Heim Plant is expected to begin operations in the fourth quarter of 2021.

Gross Margin

Gross margin is defined as revenues less product purchases. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.

Gathering and Processing segment gross 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 payments, natural gas and crude oil purchases, and the Company’s equity volume hedge settlements.

Logistics and Transportation segment gross 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, third-party transportation costs and the net inventory change.

The gross margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.

Operating Margin

Operating margin is defined as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of the Company’s operations.

Management reviews business segment gross margin and operating margin 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 its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures 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.

The following table presents a reconciliation of net income of the Company to operating margin and gross margin for the periods indicated:

  Three Months Ended December 31,  Year Ended December 31, 
  2020  2019  2020  2019 
  (In millions) 
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin                    
Net income (loss) attributable to TRC $ 33.6  $ (112.8) $ (1,553.9) $ (209.2)
Net income (loss) attributable to noncontrolling interests   112.4    97.7    228.9    250.4 
Net income (loss)   146.0    (15.1)   (1,325.0)   41.2 
Depreciation and amortization expense   217.8    252.7    865.1    971.6 
General and administrative expense   74.0    57.2    254.6    280.7 
Impairment of long-lived assets       225.3    2,442.8    225.3 
Interest (income) expense, net   98.9    96.0    391.3    337.8 
Equity (earnings) loss   (18.5)   (23.1)   (72.6)   (39.0)
Income tax expense (benefit)   38.5    (77.9)   (248.1)   (87.9)
(Gain) loss on sale or disposition of business and assets   0.4    63.8    58.4    71.1 
Write-down of assets   42.1    3.7    55.6    17.9 
(Gain) loss from sale of equity-method investment       (3.5)       (69.3)
(Gain) loss from financing activities   1.8        (45.6)   1.4 
Change in contingent considerations   (0.3)   (0.1)   (0.3)   8.7 
Other, net   (0.9)       (0.8)   0.2 
Operating margin $ 599.8  $ 579.0  $ 2,375.4  $ 1,759.7 
Operating expenses   214.7    192.1    779.8    792.9 
Gross margin $ 814.5  $ 771.1  $ 3,155.2  $ 2,552.6 


The following table presents a reconciliation of estimated net income of the Company to estimated Adjusted EBITDA for 2021:

 2021E 
 (In millions) 
Reconciliation of Estimated Net Income attributable to TRC to   
Estimated Adjusted EBITDA   
Net income attributable to TRC$300.0 
Interest expense, net 375.0 
Income tax expense 100.0 
Depreciation and amortization expense 895.0 
Equity earnings (65.0)
Distributions from unconsolidated affiliates and preferred partner interests, net 110.0 
Compensation on equity grants 60.0 
Noncontrolling interest adjustments (1) (50.0)
TRC Estimated Adjusted EBITDA$1,725.0 

(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 InvestorRelations@targaresources.com or by phone at (713) 584-1133.

Sanjay Lad
Vice President, Finance & Investor Relations

Jennifer Kneale
Chief Financial Officer

 


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