Targa Resources Corp. Reports Second Quarter 2021 Financial Results and Increases 2021 Financial Outlook

HOUSTON, Aug. 05, 2021 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported second quarter 2021 results.

Second Quarter 2021 Financial Results

Second quarter 2021 net income attributable to Targa Resources Corp. was $56.2 million compared to net income of $81.0 million for the second quarter of 2020.

The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $460.0 million for the second quarter of 2021 compared to $351.2 million for the second quarter of 2020 (see the section of this release entitled “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 July 15, 2021, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended June 30, 2021, or $0.40 per share on an annualized basis. Total cash dividends of approximately $23.3 million will be paid on August 16, 2021 on all outstanding shares of common stock to holders of record as of the close of business on July 30, 2021. Also, on July 15, 2021, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $21.8 million will be paid on August 13, 2021 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on July 30, 2021.

The Company reported distributable cash flow and free cash flow before dividends for the second quarter of 2021 of $339.5 million and $256.1 million, respectively.

Second Quarter 2021 - Sequential Quarter over Quarter Commentary

Targa reported second quarter 2021 Adjusted EBITDA of $460.0 million, representing an 11 percent decrease when compared to the first quarter of 2021. The sequential decrease in Adjusted EBITDA was primarily attributable to the aggregate benefit from the impacts of the major winter storm and higher marketing margin realized during the first quarter of 2021. Higher realized commodity prices and higher sequential volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems during the second quarter partially offset the decrease in Adjusted EBITDA. In the G&P segment, the sequential increase in segment gross margin was primarily attributable to higher Permian, Central and Badlands natural gas volumes, and higher natural gas liquids (“NGL”) and condensate prices. Natural gas inlet volumes in the Permian and Central rebounded following the impacts of the major winter storm in the first quarter, and from higher production and producer activity levels, primarily in the Permian. In the L&T segment, lower sequential gross margin was attributable to lower marketing margin, partially offset by higher pipeline transportation, fractionation and LPG export volumes. Targa’s Grand Prix NGL Pipeline and its fractionation complex in Mont Belvieu operated at record levels during the second quarter primarily due to higher supply volumes from Targa’s Permian G&P systems. Higher sequential operating expenses were attributable to an increase in repairs and maintenance, increased system throughput expenses, and higher labor and materials costs.

Capitalization and Liquidity

The Company’s total consolidated debt as of June 30, 2021 was $6,975.5 million, net of $47.6 million of debt issuance costs, with $360.0 million outstanding under Targa Resources Partners LP’s (“TRP” or the “Partnership”) accounts receivable securitization facility (the “Securitization Facility”), $6,635.7 million of outstanding TRP senior notes, and $27.4 million of finance lease liabilities.

Total consolidated liquidity as of June 30, 2021, was over $2.9 billion, including $209.0 million of cash and $40.0 million available under the Securitization Facility. As of June 30, 2021, TRC did not have any borrowings under its $670.0 million senior secured revolving credit facility (the “TRC Revolver”). TRP had $170.0 million of borrowings and $48.8 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility (the “TRP Revolver”), resulting in available senior secured revolving credit facility capacity of $1,981.2 million.

Financing Update

In April 2021, the Partnership issued a notice of redemption for all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Notes”). The notes were redeemed on May 17, 2021 with available liquidity under the TRP Revolver. As a result of the redemption of the 4¼% Notes, the Company recorded a loss due to debt extinguishment of $1.9 million.

On April 21, 2021, the Company amended the Securitization Facility to increase the facility size from $350.0 million to $400.0 million to more closely align with the Company’s expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.

Growth Projects Update

Targa has completed construction of its new 200 million cubic feet per day (“MMcf/d”) Heim Plant in the Permian Midland ahead of schedule and the plant is scheduled to commence full operations in early September. Given the Heim Plant will be highly utilized when it begins full operations and expectations of the continued strength of production growth across its Permian Midland system, Targa announced today its plans to construct a new 250 MMcf/d plant in the Permian Midland, (the “Legacy Plant”), which is expected to begin operations during the fourth quarter of 2022.  

2021 Updated Operational and Financial Expectations

Targa now estimates 2021 average Permian natural gas inlet volumes will increase around the high end of its previously disclosed 5 percent to 10 percent range over its 2020 average Permian natural gas inlet volumes, which will also result in incremental volumes through Targa’s L&T systems.

For full year 2021, Targa is increasing its estimated Adjusted EBITDA range to between $1.9 billion and $2.0 billion. Targa now estimates its year end 2021 consolidated leverage ratio to be around 3.5 times. Targa’s updated full year 2021 Adjusted EBITDA outlook assumes 2021 NGL composite barrel prices average $0.70 per gallon, crude oil prices average $65 per barrel, and Henry Hub and Waha natural gas prices to average $3.20 and $3.10 per million British Thermal Units (“MMBtu”). Targa’s estimate for 2021 net growth capital expenditures remains unchanged between $350 million and $450 million, based on announced projects and other identified spending inclusive of estimated 2021 spending on the Legacy Plant. Targa now estimates its full year 2021 net maintenance capital expenditures to be approximately $120 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 11:00 a.m. Eastern time (10:00 a.m. Central time) on August 5, 2021 to discuss its second 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/5o5x6xwo. 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 June 30,       Six Months Ended June 30,      
 2021  2020  2021 vs. 2020  2021  2020  2021 vs. 2020 
 (In millions) 
Revenues:                             
Sales of commodities$3,091.6  $1,280.6  $1,811.0  141% $6,459.3  $3,060.2  $3,399.1  111%
Fees from midstream services 324.3   242.9   81.4  34%  589.4   512.2   77.2  15%
Total revenues 3,415.9   1,523.5   1,892.4  124%  7,048.7   3,572.4   3,476.3  97%
Product purchases and fuel (1) 2,709.0   880.1   1,828.9  208%  5,545.3   2,082.2   3,463.1  166%
Gross margin (2) 706.9   643.4   63.5  10%  1,503.4   1,490.2   13.2  1%
Operating expenses (1) 184.8   163.9   20.9  13%  355.8   344.7   11.1  3%
Operating margin (2) 522.1   479.5   42.6  9%  1,147.6   1,145.5   2.1   
Depreciation and amortization expense 211.9   204.5   7.4  4%  428.0   443.6   (15.6) (4%)
General and administrative expense 63.7   61.5   2.2  4%  125.1   121.9   3.2  3%
Impairment of long-lived assets               2,442.8   (2,442.8) (100%)
Other operating (income) expense 0.7   0.4   0.3  NM   4.6   1.6   3.0  NM 
Income (loss) from operations 245.8   213.1   32.7  15%  589.9   (1,864.4)  2,454.3  132%
Interest expense, net (94.8)  (96.7)  1.9  2%  (193.2)  (194.7)  1.5  1%
Equity earnings (loss) 12.8   14.9   (2.1) (14%)  24.6   35.5   (10.9) (31%)
Gain (loss) from financing activities (1.9)  21.8   (23.7) (109%)  (16.6)  61.1   (77.7) (127%)
Other, net 0.1   0.8   (0.7) NM   0.2   0.8   (0.6) NM 
Income tax (expense) benefit (6.6)  23.2   (29.8) (128%)  (21.6)  318.5   (340.1) (107%)
Net income (loss) 155.4   177.1   (21.7) (12%)  383.3   (1,643.2)  2,026.5  123%
Less: Net income (loss) attributable to noncontrolling interests 99.2   96.1   3.1  3%  180.7   13.6   167.1  NM 
Net income (loss) attributable to Targa Resources Corp. 56.2   81.0   (24.8) (31%)  202.6   (1,656.8)  1,859.4  112%
Dividends on Series A Preferred Stock 21.8   22.9   (1.1) (5%)  43.7   45.8   (2.1) (5%)
Deemed dividends on Series A Preferred Stock    9.2   (9.2) (100%)     18.2   (18.2) (100%)
Net income (loss) attributable to common shareholders$34.4  $48.9  $(14.5) (30%) $158.9  $(1,720.8) $1,879.7  109%
Financial data:                             
Adjusted EBITDA (2)$460.0  $351.2  $108.8  31% $975.7  $779.3  $196.4  25%
Distributable cash flow (2) 339.5   273.7   65.8  24%  737.0   575.5   161.5  28%
Free cash flow (2) 256.1   130.4   125.7  96%  592.6   171.0   421.6  247%

(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) Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and 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 June 30, 2021 Compared to Three Months Ended June 30, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($1,728.1 million) and higher NGL and natural gas volumes ($269.2 million), partially offset by the unfavorable impact of hedges ($178.6 million).

The increase in fees from midstream services is primarily due to higher gathering, transportation and export volumes.

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.

The higher gross margin and operating margin in 2021 reflect both increased Gathering and Processing and Logistics and Transportation segment results, partially offset by lower results from the Company’s commodity derivative mark-to-market activity, which are reported in Other. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The increase in depreciation and amortization expense is primarily due to a full quarter of depreciation on major growth capital projects previously placed in service, including the addition of fractionation trains in Mont Belvieu, Texas and additional processing plants and associated infrastructure in the Permian Basin. The increase in depreciation and amortization expense was partially offset by the sale of assets in Channelview, Texas in October 2020.

The decrease in equity earnings is primarily due to lower earnings from the Company’s investments in Gulf Coast Fractionators (“GCF”), partially offset by an increase from Little Missouri 4 LLC (“Little Missouri 4”).

During 2021, the Partnership redeemed the 4¼% Notes resulting in a $1.9 million net loss from financing activities. During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, resulting in a $21.8 million net gain from financing activities.

The increase in income tax expense is primarily due to a larger release of the valuation allowance during the three months ended June 30, 2020, compared to the valuation allowance released during the three months ended June 30, 2021. Additionally, the increase is partially due to a higher Texas Margin Tax expense during the three months ended June 30, 2021, compared to a benefit for the three months ended June 30, 2020.

The decrease in dividends on Series A Preferred Stock (“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.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($3,585.0 million) and higher NGL volumes ($420.9 million), partially offset by lower crude marketing, petroleum products and condensate volumes ($132.1 million) and the unfavorable impact of hedges ($473.1 million).

The increase in fees from midstream services is primarily due to higher gathering, transportation and export 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 volumes, partially offset by lower crude marketing, petroleum products and condensate volumes.

The higher gross margin and operating margin in 2021 reflect both increased Gathering and Processing and Logistics and Transportation segment results, partially offset by lower results from the Company’s commodity derivative mark-to-market activity, which are reported in Other. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The decrease in depreciation and amortization expense is primarily due to a lower depreciable base associated with assets that were impaired during the first quarter of 2020 and the sale of assets in Channelview, Texas in October 2020. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including the addition of fractionation trains in Mont Belvieu, Texas and the additional processing plants and associated infrastructure in the Permian Basin.

In 2020, the Company recognized a non-cash pre-tax impairment charge of $2,442.8 million, primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with the Company’s Central operations and full impairment of the Company’s Coastal operations.

The decrease in equity earnings is primarily due to lower earnings from the Company’s investments in GCF, partially offset by an increase from Little Missouri 4.

During 2021, the Partnership redeemed the 5⅛% Senior Notes due 2025, the Targa Pipeline Partners (“TPL”) 4¾% Senior Notes due 2021 and the TPL 5⅞% Senior Notes due 2023 and the 4¼% Notes 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, resulting in a $61.1 million net gain from financing activities.

The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a decrease in the valuation allowance.                                                

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 Pipeline LLC (“Grand Prix Joint Venture”). The increase in net income attributable to noncontrolling interests was partially offset by 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.

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 “Non-GAAP Financial Measures ― Operating Margin” and “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 June 30,          Six Months Ended June 30,         
 2021  2020  2021 vs. 2020  2021  2020  2021 vs. 2020 
 (In millions, except operating statistics and price amounts) 
Gross margin (1)$ 416.3  $ 336.5  $ 79.8  24% $ 797.1  $ 704.4  $ 92.7  13%
Operating expenses (1)  115.1    99.3    15.8  16%   220.5    211.6    8.9  4%
Operating margin$ 301.2  $ 237.2  $ 64.0  27% $ 576.6  $ 492.8  $ 83.8  17%
Operating statistics (2):                                   
Plant natural gas inlet, MMcf/d (3),(4)                                   
Permian Midland (5)  1,929.7    1,698.9    230.8  14%   1,794.7    1,677.0    117.7  7%
Permian Delaware  836.2    651.6    184.6  28%   787.2    689.3    97.9  14%
Total Permian  2,765.9    2,350.5    415.4       2,581.9    2,366.3    215.6    
                                    
SouthTX  194.9    265.1    (70.2) (26%)   185.7    275.7    (90.0) (33%)
North Texas  181.4    197.8    (16.4) (8%)   178.4    210.6    (32.2) (15%)
SouthOK  411.4    439.8    (28.4) (6%)   393.4    501.9    (108.5) (22%)
WestOK  212.5    251.2    (38.7) (15%)   207.6    271.4    (63.8) (24%)
Total Central  1,000.2    1,153.9    (153.7)      965.1    1,259.6    (294.5)   
                                    
Badlands (6)  143.4    111.6    31.8  28%   139.1    135.6    3.5  3%
Total Field  3,909.5    3,616.0    293.5       3,686.1    3,761.5    (75.4)   
                                    
Coastal  616.6    713.0    (96.4) (14%)   634.5    748.8    (114.3) (15%)
                                    
Total  4,526.1    4,329.0    197.1  5%   4,320.6    4,510.3    (189.7) (4%)
NGL production, MBbl/d (4)                                   
Permian Midland (5)  279.4    245.0    34.4  14%   258.4    245.0    13.4  5%
Permian Delaware  111.7    89.6    22.1  25%   104.1    93.0    11.1  12%
Total Permian  391.1    334.6    56.5       362.5    338.0    24.5    
                                    
SouthTX  25.8    28.8    (3.0) (10%)   21.7    28.5    (6.8) (24%)
North Texas  20.4    23.5    (3.1) (13%)   19.8    24.9    (5.1) (20%)
SouthOK  50.4    51.3    (0.9) (2%)   47.1    59.0    (11.9) (20%)
WestOK  17.0    21.0    (4.0) (19%)   16.5    22.1    (5.6) (25%)
Total Central  113.6    124.6    (11.0)      105.1    134.5    (29.4)   
                                    
Badlands  16.2    13.9    2.3  17%   15.9    16.0    (0.1) (1%)
Total Field  520.9    473.1    47.8       483.5    488.5    (5.0)   
                                    
Coastal  35.7    43.2    (7.5) (17%)   37.8    46.0    (8.2) (18%)
                                    
Total  556.6    516.3    40.3  8%   521.3    534.5    (13.2) (2%)
Crude oil, Badlands, MBbl/d  138.9    157.9    (19.0) (12%)   137.6    167.5    (29.9) (18%)
Crude oil, Permian, MBbl/d  36.7    40.2    (3.5) (9%)   35.8    45.6    (9.8) (21%)
Natural gas sales, BBtu/d (4)  2,207.5    2,048.9    158.6  8%   2,082.4    2,103.0    (20.6) (1%)
NGL sales, MBbl/d (4)  391.9    395.0    (3.1) (1%)   370.5    414.3    (43.8) (11%)
Condensate sales, MBbl/d  15.2    16.1    (0.9) (6%)   15.2    17.3    (2.1) (12%)
Average realized prices - inclusive of hedges (7):                                
Natural gas, $/MMBtu  2.45    1.03    1.42  138%   2.48    0.98    1.50  153%
NGL, $/gal  0.51    0.19    0.32  168%   0.49    0.21    0.28  133%
Condensate, $/Bbl  59.06    28.13    30.93  110%   52.97    36.61    16.36  45%

(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 quarter and the denominator is the number of calendar days during the quarter.
(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) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
(7) 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 gross margin of Gathering and Processing segment:

  Three Months Ended June 30, 2021  Three Months Ended June 30, 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)  18.1  $(0.71) $(12.8)  17.3  $0.53  $9.2 
NGL (MMgal)  133.8   (0.18)  (24.4)  100.2   0.22   21.7 
Crude oil (MBbl)  0.5   (12.69)  (6.7)  0.5   29.85   14.1 
          $(43.9)         $45.0 

(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

  Six Months Ended June 30, 2021  Six Months Ended June 30, 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)  36.1  $(0.72) $(26.0)  33.1  $0.73  $24.1 
NGL (MMgal)  269.6   (0.17)  (46.9)  195.7   0.20   39.2 
Crude oil (MBbl)  1.1   (8.32)  (8.9)  0.9   21.24   19.7 
          $(81.8)         $83.0 

(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020

The increase in gross margin was primarily due to higher realized commodity prices and higher natural gas inlet volumes resulting in increased margin in the Permian and Badlands, partially offset by lower volumes in the Central and Coastal regions. In the Permian, natural gas inlet volumes increased due to higher production and producer activity, as well as the addition of the Peregrine Plant in the second quarter of 2020 and the Gateway Plant in the third quarter of 2020. In the Badlands, natural gas inlet volumes increased due to higher producer activity. In the Central and Coastal regions, natural gas inlet volumes decreased 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 the addition of the Peregrine and Gateway plants in 2020 and increased activity levels in the Permian, which resulted in increased materials, labor costs and ad valorem taxes.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

The increase in gross margin was primarily due to higher realized commodity prices and higher Permian natural gas inlet volumes resulting in higher margin, partially offset by the short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. In the Permian, natural gas inlet volumes increased due to higher production, higher producer activity and the addition of the Peregrine and Gateway plants in 2020. 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 the addition of the Peregrine and Gateway plants in 2020 and increased activity levels in the Permian, which resulted in increased ad valorem taxes, materials and labor costs.

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 NGL Pipeline, 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 June 30,          Six Months Ended June 30,     
 2021  2020  2021 vs. 2020  2021  2020  2021 vs. 2020 
 (In millions, except operating statistics) 
Gross margin (1)$362.1  $297.1  $65.0  22%  $776.6  $660.7  $115.9  18% 
Operating expenses (1) 70.7   65.6   5.1  8%   136.5   135.2   1.3  1% 
Operating margin$291.4  $231.5  $59.9  26%  $640.1  $525.5  $114.6  22% 
Operating statistics MBbl/d (2):                               
Pipeline throughput (3) 391.7   256.1   135.6  53%   367.2   258.9   108.3  42% 
Fractionation volumes 643.7   579.3   64.4  11%   595.0   602.3   (7.3) (1%) 
Export volumes (4) 340.6   253.8   86.8  34%   312.1   261.3   50.8  19% 
NGL sales 900.0   692.6   207.4  30%   893.2   720.4   172.8  24% 

(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) Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.
(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 June 30, 2021 Compared to Three Months Ended June 30, 2020

The increase in gross margin was primarily due to higher pipeline transportation and fractionation volumes, higher marketing margin and higher LPG export volumes. Pipeline transportation and fractionation volumes benefited from higher supply volumes from the Company’s Permian Gathering and Processing systems. Marketing margin increased due to greater optimization opportunities. Higher LPG export volumes benefited from the expansion of the Company’s LPG export capabilities.

Operating expenses were higher due to higher repairs and maintenance, increased system throughput expenses and higher ad valorem taxes primarily due to system expansions, partially offset by cost reduction measures and the sale of assets in Channelview, Texas, in 2020.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

The increase in gross margin was primarily due to higher pipeline transportation 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. Other drivers included higher marketing margin due to greater optimization opportunities and higher LPG export volumes, partially offset by lower LPG export terminaling fees.

Operating expenses were flat. Higher repairs and maintenance, increased pipeline throughput expenses and higher ad valorem taxes primarily due to system expansions, were offset by cost reduction measures and the sale of assets in Channelview, Texas, in 2020.

Other

  Three Months Ended June 30,      Six Months Ended June 30,     
  2021  2020  2021 vs. 2020  2021  2020  2021 vs. 2020 
  (In millions) 
Gross margin $(70.5) $10.8  $(81.3) $(69.1) $127.2  $(196.3)
Operating margin $(70.5) $10.8  $(81.3) $(69.1) $127.2  $(196.3)

Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s future commodity purchases and sales and natural gas transportation basis risk within the Company’s Logistics and Transportation segment.

About Targa 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.

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, 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

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, and are no longer outstanding. The Company defines 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 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 June 30,  Six Months Ended June 30, 
  2021  2020  2021  2020 
  (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 $56.2  $81.0  $202.6  $(1,656.8)
Income attributable to TRP preferred limited partners     2.8      5.6 
Interest (income) expense, net  94.8   96.7   193.2   194.7 
Income tax expense (benefit)  6.6   (23.2)  21.6   (318.5)
Depreciation and amortization expense  211.9   204.5   428.0   443.6 
Impairment of long-lived assets           2,442.8 
(Gain) loss on sale or disposition of business and assets  (0.4)  (0.7)  (0.2)   
Write-down of assets  1.1      4.7    
(Gain) loss from financing activities (1)  1.9   (21.8)  16.6   (61.1)
Equity (earnings) loss  (12.8)  (14.9)  (24.6)  (35.5)
Distributions from unconsolidated affiliates and preferred partner
interests, net
  26.9   27.7   60.2   53.4 
Compensation on equity grants  15.0   16.1   29.9   33.1 
Risk management activities  69.7   (10.4)  68.2   (125.9)
Severance and related benefits     6.5      6.5 
Noncontrolling interests adjustments (2)  (10.9)  (13.1)  (24.5)  (202.6)
TRC Adjusted EBITDA $460.0  $351.2  $975.7  $779.3 
Distributions to TRP preferred limited partners     (2.8)     (5.6)
Interest expense on debt obligations (3)  (95.5)  (94.1)  (194.2)  (191.2)
Maintenance capital expenditures  (26.2)  (26.8)  (47.2)  (53.7)
Noncontrolling interests adjustments of maintenance capital
expenditures
  2.0   1.8   4.0   2.3 
Cash taxes  (0.8)  44.4   (1.3)  44.4 
Distributable Cash Flow $339.5  $273.7  $737.0  $575.5 
Growth capital expenditures, net (4)  (83.4)  (143.3)  (144.4)  (404.5)
Free Cash Flow $256.1  $130.4  $592.6  $171.0 

(1) Gains or losses on debt repurchases or early debt extinguishments.
(2) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests), net of non-cash accretion of noncontrolling interests.
(3) Excludes amortization of interest expense.
(4) Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.

Gross Margin

The Company defines gross margin 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 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, fuel, 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 June 30,  Six Months Ended June 30, 
  2021  2020  2021  2020 
  (In millions) 
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin                
Net income (loss) attributable to TRC $56.2  $81.0  $202.6  $(1,656.8)
Net income (loss) attributable to noncontrolling interests  99.2   96.1   180.7   13.6 
Net income (loss)  155.4   177.1   383.3   (1,643.2)
Depreciation and amortization expense  211.9   204.5   428.0   443.6 
General and administrative expense  63.7   61.5   125.1   121.9 
Impairment of long-lived assets           2,442.8 
Interest (income) expense, net  94.8   96.7   193.2   194.7 
Equity (earnings) loss  (12.8)  (14.9)  (24.6)  (35.5)
Income tax expense (benefit)  6.6   (23.2)  21.6   (318.5)
(Gain) loss on sale or disposition of business and assets  (0.4)  (0.7)  (0.2)   
Write-down of assets  1.1      4.7    
(Gain) loss from financing activities  1.9   (21.8)  16.6   (61.1)
Other, net  (0.1)  0.3   (0.1)  0.8 
Operating margin $522.1  $479.5  $1,147.6  $1,145.5 
Operating expenses  184.8   163.9   355.8   344.7 
Gross margin $706.9  $643.4  $1,503.4  $1,490.2 

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

 2021E(1) 
 (In millions) 
Reconciliation of Estimated Net Income attributable to TRC to   
Estimated Adjusted EBITDA   
Net income attributable to TRC$485.0 
Interest expense, net 375.0 
Income tax expense 70.0 
Depreciation and amortization expense 870.0 
Equity (earnings) loss (55.0)
Distributions from unconsolidated affiliates and preferred partner interests, net 115.0 
Compensation on equity grants 60.0 
Risk management activities and other 80.0 
Noncontrolling interests adjustments (2) (50.0)
TRC Estimated Adjusted EBITDA$1,950.0 

(1) Represents the midpoint of estimated full year 2021 Adjusted EBITDA.        
(2) Noncontrolling interest portion of depreciation and amortization expense.

Forward-Looking Statements

Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the impact of pandemics 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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