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Targa Resources Corp. Reports Third Quarter 2021 Financial Results

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Increases 2021 Financial Outlook and Announces Updated Capital Allocation Strategy

HOUSTON, Nov. 04, 2021 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported third quarter 2021 results.

Third Quarter 2021 Financial Results

Third quarter 2021 net income attributable to Targa Resources Corp. was $182.2 million compared to net income of $69.3 million for the third quarter of 2020.

The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $505.9 million for the third quarter of 2021 compared to $419.1 million for the third quarter of 2020 (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of adjusted EBITDA, distributable cash flow, adjusted free cash flow, adjusted gross margin and adjusted 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 October 14, 2021, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended September 30, 2021, or $0.40 per share on an annualized basis. Total cash dividends of approximately $23.3 million will be paid on November 15, 2021 on all outstanding shares of common stock to holders of record as of the close of business on October 29, 2021. Also, on October 14, 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 November 12, 2021 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on October 29, 2021.

The Company reported distributable cash flow and adjusted free cash flow before dividends for the third quarter of 2021 of $383.9 million and $297.2 million, respectively.

2021 Updated Operational and Financial Expectations

Targa now estimates 2021 average Permian natural gas inlet volumes to exceed the top end of its previously disclosed 5 percent to 10 percent growth range over 2020 average Permian natural gas inlet volumes, which will also result in incremental volumes through Targa’s Logistics and Transportation (“L&T”) systems.

For full year 2021, Targa now estimates adjusted EBITDA to exceed the top end of its previously disclosed range of $1.9 billion to $2.0 billion, and Targa’s year-end 2021 consolidated leverage ratio is estimated to be about 3.25 times. Targa now expects its 2021 net growth capital expenditures to be around $450 million due to increasing activity levels and some additional spending for long-lead items for Targa’s next gas plant in Permian Midland. The estimate for full year 2021 net maintenance capital expenditures is unchanged at approximately $120 million.

“Our outperformance as we have moved through this year is reflective of the strength of volume growth across Targa’s integrated asset footprint, coupled with our success in utilizing commercial contract structures that protect our downside and allow us to benefit in a rising commodity price environment. With consolidated leverage now at the midpoint of our long-term target range, we are in position to return capital to our shareholders sooner than previous expectations,” said Matt Meloy, Chief Executive Officer of Targa. “With year-end leverage estimated to be about 3.25 times, over the short, medium, and long-term, we have the flexibility to return capital to our shareholders through common dividend increases and share repurchases, while executing on the simplification of our capital structure and continuing to invest in accretive growth opportunities across our core integrated strategy. We remain focused on maintaining our balance sheet strength to preserve Targa’s financial flexibility through business cycles and position Targa to maximize shareholder value.”

Capital Allocation Update

For the fourth quarter of 2021, Targa intends to recommend to its board of directors an increase to its common dividend to $0.35 per common share or $1.40 per common share annualized. The initial recommended common dividend per share increase is expected to be effective for the fourth quarter of 2021 and payable in February 2022. An annualized common dividend of $1.40 per share represents about 30 percent of Targa’s expected 2021 adjusted free cash flow. Beyond 2022, Targa expects to be in position to provide modest annual increases to its common dividend.

Given year-end 2021 consolidated leverage is estimated to be in the lower end of Targa’s target range, the Company is also in position to opportunistically repurchase common stock under its existing $500 million authorized share repurchase program (the “Share Repurchase Program”) and will continue to simplify its capital structure through the redemption of outstanding shares of Targa Series A Preferred Stock (“Series A Preferred”) over time.

There is no change to Targa’s assumption that it expects to repurchase its interests in its development company joint ventures from investment vehicles affiliated with Stonepeak Infrastructure Partners for approximately $925 million in January 2022.

Consistent with previous years, Targa plans to detail its full year 2022 operational and financial outlook in February 2022 in conjunction with its fourth quarter 2021 earnings announcement.

“We believe that Targa provides a unique value proposition to our shareholders across cycles as we continue to invest in attractive growth capital opportunities, simplify our capital structure and advance towards achieving investment grade ratings. Our updated capital allocation strategy aligns well with these priorities while increasing the amount of capital that we can return to our shareholders over time,” said Meloy. “The tailwinds of the current commodity price environment are welcome, but more importantly, the strength of our balance sheet will allow us to capitalize on opportunities across cycles, and maintaining that flexibility is a priority to our strategy going forward.”

Third Quarter 2021 - Sequential Quarter over Quarter Commentary

Targa reported third quarter 2021 adjusted EBITDA of $505.9 million, representing a 10 percent increase when compared to the second quarter of 2021. The sequential increase in adjusted EBITDA was primarily attributable to higher realized commodity prices and higher Permian volumes across Targa’s Gathering and Processing (“G&P”) and L&T systems during the third quarter. In the G&P segment, record Permian natural gas volumes and higher commodity prices drove the sequential increase in segment adjusted gross margin, partially offset by lower volumes in Coastal, which were impacted by the effects of Hurricane Ida. The increase in natural gas inlet volumes in the Permian were attributable to an increase in production and activity levels. In the L&T segment, higher sequential pipeline transportation and fractionation volumes were partially offset by lower LPG export volumes. Targa’s Grand Prix NGL Pipeline (“Grand Prix”) and its fractionation complex in Mont Belvieu operated at record levels during the third quarter primarily due to higher supply volumes from Targa’s Permian G&P systems. Lower sequential LPG export volumes were attributable to general maintenance at Targa’s Galena Park export facility completed during the third quarter, which reduced the number of available loading days. Higher sequential operating expenses in the G&P segment were attributable to system expansions in the Permian with the addition of the Heim Plant in early September.

Capitalization and Liquidity

The Company’s total consolidated debt as of September 30, 2021 was $6,786.7 million, net of $46.3 million of debt issuance costs, with $340.0 million outstanding under Targa Resources Partners LP’s (“TRP” or the “Partnership”) accounts receivable securitization facility (the “Securitization Facility”), $6,465.7 million of outstanding TRP senior notes, and $27.3 million of finance lease liabilities.

Total consolidated liquidity as of September 30, 2021, was over $3.1 billion, including $228.6 million of cash and $60.0 million available under the Securitization Facility. As of September 30, 2021, TRC did not have any borrowings under its $670.0 million senior secured revolving credit facility (the “TRC Revolver”). TRP did not have any borrowings and had $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 $2,151.2 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 November 4, 2021 to discuss its third 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/s3rh8j3u. 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 September 30,

Nine Months Ended
September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(In millions)

Revenues:

Sales of commodities

$

4,118.1

$

1,840.8

$

2,277.3

124

%

$

10,577.3

$

4,900.8

$

5,676.5

116

%

Fees from midstream services

341.6

274.3

67.3

25

%

930.9

786.7

144.2

18

%

Total revenues

4,459.7

2,115.1

2,344.6

111

%

11,508.2

5,687.5

5,820.7

102

%

Product purchases and fuel (1)

3,614.7

1,322.9

2,291.8

173

%

9,159.8

3,405.1

5,754.7

169

%

Operating expenses (1)

189.4

162.2

27.2

17

%

545.3

506.8

38.5

8

%

Depreciation and amortization expense

222.8

203.7

19.1

9

%

650.9

647.3

3.6

1

%

General and administrative expense

67.3

58.6

8.7

15

%

192.4

180.6

11.8

7

%

Impairment of long-lived assets

2,442.8

(2,442.8

)

(100

%)

Other operating (income) expense

(1.0

)

72.2

(73.2

)

(101

%)

3.4

73.8

(70.4

)

(95

%)

Income (loss) from operations

366.5

295.5

71.0

24

%

956.4

(1,568.9

)

2,525.3

161

%

Interest expense, net

(91.0

)

(97.7

)

6.7

7

%

(284.2

)

(292.4

)

8.2

3

%

Equity earnings (loss)

14.3

18.6

(4.3

)

(23

%)

38.9

54.1

(15.2

)

(28

%)

Gain (loss) from financing activities

(13.7

)

13.7

100

%

(16.6

)

47.4

(64.0

)

(135

%)

Other, net

0.2

1.4

(1.2

)

NM

0.3

2.2

(1.9

)

NM

Income tax (expense) benefit

(2.0

)

(31.9

)

29.9

94

%

(23.5

)

286.6

(310.1

)

(108

%)

Net income (loss)

288.0

172.2

115.8

67

%

671.3

(1,471.0

)

2,142.3

146

%

Less: Net income (loss) attributable to noncontrolling interests

105.8

102.9

2.9

3

%

286.5

116.5

170.0

146

%

Net income (loss) attributable to Targa Resources Corp.

182.2

69.3

112.9

163

%

384.8

(1,587.5

)

1,972.3

124

%

Dividends on Series A Preferred Stock

21.8

22.9

(1.1

)

(5

%)

65.5

68.8

(3.3

)

(5

%)

Deemed dividends on Series A Preferred Stock

9.5

(9.5

)

(100

%)

27.7

(27.7

)

(100

%)

Net income (loss) attributable to common shareholders

$

160.4

$

36.9

$

123.5

NM

$

319.3

$

(1,684.0

)

$

2,003.3

119

%

Financial data:

Adjusted EBITDA (2)

$

505.9

$

419.1

$

86.8

21

%

$

1,481.4

$

1,198.5

$

282.9

24

%

Distributable cash flow (2)

383.9

294.7

89.2

30

%

1,120.7

878.9

241.8

28

%

Adjusted free cash flow (2)

297.2

189.3

107.9

57

%

892.8

360.4

532.4

148

%

_______________
(1) Beginning in 2021, the Company reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to Targa’s revenue-generating activities and align with the Company’s evaluation of the performance of the business.
(2) Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Non-GAAP Financial Measures.”
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful or material.

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

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($2,259.0 million) and higher NGL and natural gas volumes ($226.6 million), partially offset by the unfavorable impact of hedges ($192.8 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, partially offset by lower terminaling and storage fees.

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

Operating expenses were higher due to increased labor costs and higher repairs and maintenance primarily due to increased activity levels and system expansions.

See “—Results of Operations—By Reportable Segment” for additional information 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 increase in general and administrative expense is primarily due to higher compensation and benefits and an increase in insurance costs.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of the Company’s assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.

The decrease in interest expense, net is primarily due to lower net borrowings, partially offset by lower capitalized interest resulting from lower growth capital investments.

During the third quarter of 2020, the Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.

The decrease in income tax expense is primarily due to a larger release of the valuation allowance in 2021 compared to 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.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($5,840.0 million) and higher NGL and natural gas volumes ($650.5 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($148.0 million) and the unfavorable impact of hedges ($666.0 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, partially offset by lower terminaling and storage fees.

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes, partially offset by lower petroleum products, crude marketing and condensate volumes.

Operating expenses were higher due to increased labor costs, higher repairs and maintenance and higher ad valorem taxes primarily due to increased activity levels and system expansions.

See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.

The increase in general and administrative expense is primarily due to higher compensation and benefits and an increase in insurance costs, partially offset by a decrease in professional fees.

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.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of the Company’s assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.

The decrease in interest expense, net is primarily due to lower net borrowings, partially offset by lower capitalized interest resulting from lower growth capital investments.

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

During 2021, the Partnership redeemed the 5⅛% Notes, the TPL Notes 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 $47.4 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. 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 adjusted 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 adjusted operating margin and adjusted gross margin, see “Non-GAAP Financial Measures ― Adjusted Operating Margin” and “Non-GAAP Financial Measures ― Adjusted 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 September 30,

Nine Months Ended September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(In millions, except operating statistics and price amounts)

Operating margin

$

361.4

$

261.0

$

100.4

38

%

$

938.2

$

753.7

$

184.5

24

%

Operating expenses (1)

122.8

102.1

20.7

20

%

343.1

313.6

29.5

9

%

Adjusted gross margin (1)

$

484.2

$

363.1

$

121.1

33

%

$

1,281.3

$

1,067.3

$

214.0

20

%

Operating statistics (2):

Plant natural gas inlet, MMcf/d (3),(4)

Permian Midland (5)

2,109.2

1,811.5

297.7

16

%

1,900.7

1,722.1

178.6

10

%

Permian Delaware

842.7

758.1

84.6

11

%

805.9

712.4

93.5

13

%

Total Permian

2,951.9

2,569.6

382.3

2,706.6

2,434.5

272.1

SouthTX

180.5

233.6

(53.1

)

(23

%)

184.0

261.5

(77.5

)

(30

%)

North Texas

180.7

197.8

(17.1

)

(9

%)

179.2

206.3

(27.1

)

(13

%)

SouthOK

420.6

386.9

33.7

9

%

402.6

463.3

(60.7

)

(13

%)

WestOK

219.4

233.6

(14.2

)

(6

%)

211.6

258.7

(47.1

)

(18

%)

Total Central

1,001.2

1,051.9

(50.7

)

977.4

1,189.8

(212.4

)

Badlands (6)

135.2

137.0

(1.8

)

(1

%)

137.8

136.1

1.7

1

%

Total Field

4,088.3

3,758.5

329.8

3,821.8

3,760.4

61.4

Coastal

527.1

522.8

4.3

1

%

598.3

672.9

(74.6

)

(11

%)

Total

4,615.4

4,281.3

334.1

8

%

4,420.1

4,433.3

(13.2

)

NGL production, MBbl/d (4)

Permian Midland (5)

307.3

253.0

54.3

21

%

274.8

247.6

27.2

11

%

Permian Delaware

119.8

105.3

14.5

14

%

109.3

97.1

12.2

13

%

Total Permian

427.1

358.3

68.8

384.1

344.7

39.4

SouthTX

24.2

29.2

(5.0

)

(17

%)

22.6

28.7

(6.1

)

(21

%)

North Texas

21.0

23.7

(2.7

)

(11

%)

20.2

24.5

(4.3

)

(18

%)

SouthOK

52.1

45.9

6.2

14

%

48.8

54.6

(5.8

)

(11

%)

WestOK

15.7

19.3

(3.6

)

(19

%)

16.2

21.2

(5.0

)

(24

%)

Total Central

113.0

118.1

(5.1

)

107.8

129.0

(21.2

)

Badlands

16.2

17.0

(0.8

)

(5

%)

16.0

16.3

(0.3

)

(2

%)

Total Field

556.3

493.4

62.9

507.9

490.0

17.9

Coastal

28.0

32.5

(4.5

)

(14

%)

34.5

41.5

(7.0

)

(17

%)

Total

584.3

525.9

58.4

11

%

542.4

531.5

10.9

2

%

Crude oil, Badlands, MBbl/d

140.8

146.4

(5.6

)

(4

%)

138.7

160.4

(21.7

)

(14

%)

Crude oil, Permian, MBbl/d

34.1

44.6

(10.5

)

(24

%)

35.3

45.3

(10.0

)

(22

%)

Natural gas sales, BBtu/d (4)

2,319.9

2,032.3

287.6

14

%

2,162.5

2,079.3

83.2

4

%

NGL sales, MBbl/d (4)

412.6

389.5

23.1

6

%

384.7

406.0

(21.3

)

(5

%)

Condensate sales, MBbl/d

15.4

13.6

1.8

13

%

15.3

16.1

(0.8

)

(5

%)

Average realized prices - inclusive of hedges (7):

Natural gas, $/MMBtu

3.51

1.34

2.17

162

%

2.85

1.10

1.75

159

%

NGL, $/gal

0.69

0.29

0.40

138

%

0.56

0.24

0.32

133

%

Condensate, $/Bbl

64.41

43.49

20.92

48

%

56.86

38.56

18.30

47

%

_______________
(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 adjusted gross margin of the Gathering and Processing segment:

Three Months Ended September 30, 2021

Three Months Ended September 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)

20.5

$

(1.52

)

$

(31.2

)

17.5

$

0.20

$

3.5

NGL (MMgal)

150.4

(0.35

)

(52.4

)

126.4

0.08

10.5

Crude oil (MBbl)

0.5

(18.80

)

(9.4

)

0.5

16.75

8.0

$

(93.0

)

$

22.0

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

Nine Months Ended September 30, 2021

Nine Months Ended September 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)

56.6

$

(1.01

)

$

(57.2

)

50.6

$

0.55

$

27.7

NGL (MMgal)

420.0

(0.24

)

(99.3

)

322.1

0.15

49.7

Crude oil (MBbl)

1.6

(11.38

)

(18.2

)

1.4

19.72

27.7

$

(174.7

)

$

105.1

_______________
(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 September 30, 2021 Compared to Three Months Ended September 30, 2020

The increase in adjusted gross margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in increased margin primarily in the Permian, partially offset by lower volumes in the Central region. In the Permian, natural gas inlet volumes increased due to higher production and producer activity, as well as the addition of the Gateway and Heim plants during the third quarters of 2020 and 2021, respectively. In the Badlands and Coastal regions, natural gas inlet volumes were relatively flat, while in the Central region the decrease was due to lower production and continued low producer activity. Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian and the addition of the Gateway and Heim plants in the third quarters of 2020 and 2021, respectively, which resulted in increased labor costs, materials and chemicals.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in adjusted gross margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in higher margin primarily in the Permian, 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, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant in the third quarter of 2021. In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal regions was due to continued low producer activity. Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant in the third quarter of 2021, which resulted in increased labor costs and materials.

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 September 30,

Nine Months Ended September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(In millions, except operating statistics and price amounts)

Operating margin

$

280.7

$

280.4

$

0.3

$

920.5

$

806.0

$

114.5

14

%

Operating expenses (1)

67.3

61.7

5.6

9

%

204.1

196.8

7.3

4

%

Adjusted gross margin (1)

$

348.0

$

342.1

$

5.9

2

%

$

1,124.6

$

1,002.8

$

121.8

12

%

Operating statistics MBbl/d (2):

Pipeline throughput (3)

416.5

300.9

115.6

38

%

383.8

273.0

110.8

41

%

Fractionation volumes

662.0

589.5

72.5

12

%

617.5

598.0

19.5

3

%

Export volumes (4)

293.2

308.5

(15.3

)

(5

%)

305.7

277.2

28.5

10

%

NGL sales

857.3

724.1

133.2

18

%

881.1

721.6

159.5

22

%

(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 September 30, 2021 Compared to Three Months Ended September 30, 2020

The increase in adjusted gross margin was primarily due to higher pipeline transportation and fractionation volumes, partially offset by lower LPG export volumes and lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems. LPG export volumes were lower due to reduced short-term loading capacity as a result of repairs and maintenance that were completed in the third quarter of 2021. Marketing margin decreased due to fewer optimization opportunities.

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.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in adjusted gross margin was primarily due to higher pipeline transportation and fractionation volumes that benefited from higher supply volumes from the Company’s Permian Gathering and Processing systems, partially offset by short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. Other drivers included higher marketing margin due to greater optimization opportunities and higher LPG export volumes, partially offset by lower LPG export terminal fees.

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.

Other

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021 vs. 2020

2021

2020

2021 vs. 2020

(In millions)

Operating margin

$

13.5

$

88.6

$

(75.1

)

$

(55.6

)

$

215.9

$

(271.5

)

Gross margin

$

13.5

$

88.6

$

(75.1

)

$

(55.6

)

$

215.9

$

(271.5

)

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

About Targa Resources Corp.

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

Targa is a FORTUNE 500 company and is included in the S&P 400.

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

Non-GAAP Financial Measures

This press release includes the Company’s non-GAAP financial measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow, adjusted gross margin and adjusted 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. Adjusted gross margin, adjusted operating margin, adjusted EBITDA, distributable cash flow, and adjusted free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures are gross margin, income (loss) from operations and net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to the comparable GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect 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 Adjusted Free Cash Flow

The Company defines distributable cash flow as adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020, and are no longer outstanding. The Company defines adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

The following table presents a reconciliation of net income (loss) attributable to TRC to adjusted EBITDA, distributable cash flow and adjusted free cash flow for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021

2020

(In millions)

Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow

Net income (loss) attributable to TRC

$

182.2

$

69.3

$

384.8

$

(1,587.5

)

Income attributable to TRP preferred limited partners

2.8

8.4

Interest (income) expense, net

91.0

97.7

284.2

292.4

Income tax expense (benefit)

2.0

31.9

23.5

(286.6

)

Depreciation and amortization expense

222.8

203.7

650.9

647.3

Impairment of long-lived assets

2,442.8

(Gain) loss on sale or disposition of business and assets

(1.5

)

58.0

(1.7

)

58.0

Write-down of assets

0.5

13.5

5.0

13.5

(Gain) loss from financing activities (1)

13.7

16.6

(47.4

)

Equity (earnings) loss

(14.3

)

(18.6

)

(38.9

)

(54.1

)

Distributions from unconsolidated affiliates and preferred partner interests, net

28.2

28.2

88.4

81.6

Compensation on equity grants

14.7

16.4

44.6

49.5

Risk management activities

(12.6

)

(88.3

)

55.6

(214.2

)

Severance and related benefits

6.5

Noncontrolling interests adjustments (2)

(7.1

)

(9.2

)

(31.6

)

(211.7

)

TRC Adjusted EBITDA

$

505.9

$

419.1

$

1,481.4

$

1,198.5

Distributions to TRP preferred limited partners

(2.8

)

(8.4

)

Interest expense on debt obligations (3)

(91.6

)

(98.2

)

(285.8

)

(289.5

)

Maintenance capital expenditures

(31.1

)

(27.3

)

(78.4

)

(67.7

)

Noncontrolling interests adjustments of maintenance capital expenditures

1.5

3.9

5.5

1.6

Cash taxes

(0.8

)

(2.0

)

44.4

Distributable Cash Flow

$

383.9

$

294.7

$

1,120.7

$

878.9

Growth capital expenditures, net (4)

(86.7

)

(105.4

)

(227.9

)

(518.5

)

Adjusted Free Cash Flow

$

297.2

$

189.3

$

892.8

$

360.4

_______________
(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.

Adjusted Gross Margin

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

Adjusted Operating Margin

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

Management reviews business segment adjusted 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.

The following table presents a reconciliation of income (loss) from operations to adjusted operating margin and gross margin to adjusted gross margin for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021

2020

(In millions)

Reconciliation of Income (Loss) from Operations to Adjusted Operating Margin

Income (loss) from operations

$

366.5

$

295.5

$

956.4

$

(1,568.9

)

Depreciation and amortization expense

222.8

203.7

650.9

647.3

General and administrative expense

67.3

58.6

192.4

180.6

Impairment of long-lived assets

2,442.8

(Gain) loss on sale or disposition of business and assets

(1.5

)

58.0

(1.7

)

58.0

Write-down of assets

0.5

13.5

5.0

13.5

Other, net

0.7

0.1

2.3

Adjusted operating margin

$

655.6

$

630.0

$

1,803.1

$

1,775.6


Three Months Ended September 30,

Nine Months Ended September 30,

2021

2020

2021

2020

(In millions)

Reconciliation of Gross Margin to Adjusted Gross Margin

Gross Margin

$

622.2

$

588.5

$

1,697.5

$

1,635.1

Depreciation and amortization expense

222.8

203.7

650.9

647.3

Adjusted gross margin

$

845.0

$

792.2

$

2,348.4

$

2,282.4

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

$

555.0

Interest expense, net

370.0

Income tax expense

50.0

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

75.0

Noncontrolling interests adjustments (1)

(40.0

)

TRC Estimated Adjusted EBITDA

$

2,000.0

_______________
(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