trgp-8k_20201105.htm
false 0001389170 0001389170 2020-11-05 2020-11-05

  

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported):

November 5, 2020

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

 

 

 

 

 

 

 

 

 

 

Delaware

(State or other jurisdiction

of incorporation or organization)

 

001-34991

(Commission

File Number)

 

20-3701075

(IRS Employer

Identification No.)

 

811 Louisiana, Suite 2100

Houston, TX 77002

(Address of principal executive office and Zip Code)

 

(713) 584-1000

(Registrants’ telephone number, including area code)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

 

 

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

 

 

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

 

 

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

Trading Symbol(s)

Name of exchange on which registered

Common Stock

TRGP

New York Stock Exchange

 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). Emerging Growth Company 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 

 

 


   

Item 2.02

 

Results of Operations and Financial Condition.

 

On November 5, 2020, Targa Resources Corp. (the “Company”) issued a press release regarding its financial results for the three months ended September 30, 2020. A conference call to discuss these results is scheduled for 11:00 a.m. Eastern time (10:00 a.m. Central time) on Thursday, November 5, 2020. The conference call will be webcast live and a replay of the webcast will be available through the Investors section of the Company’s web site (http://www.targaresources.com). A copy of the earnings press release is furnished as Exhibit 99.1 to this report, which is hereby incorporated by reference into this Item 2.02.

 

The press release and accompanying schedules and/or the conference call discussions include the non-generally accepted accounting principles (“non-GAAP”) financial measures of distributable cash flow, free cash flow, gross margin, operating margin and adjusted EBITDA. The press release provides reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net cash provided by operating activities, net income (loss) or any other GAAP measure of liquidity or financial performance.

 

The information furnished pursuant to this Item 2.02, including Exhibit 99.1, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

 

Item 9.01

 

Financial Statements and Exhibits.

 

(d) Exhibits

 

Exhibit

 

 

Number

 

Description

Exhibit 99.1

 

Targa Resources Corp. Press Release dated November 5, 2020.

 

 

 

Exhibit 104

 

Cover Page Interactive Data File (embedded within the Inline XBRL document).

 

 

 

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

Targa Resources Corp.

 

 

Date: November 5, 2020

By:

/s/ Jennifer R. Kneale

 

 

Jennifer R. Kneale

 

 

Chief Financial Officer

(Principal Financial Officer)

 

trgp-ex991_25.htm

 

Exhibit 99.1

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

Targa Resources Corp. Reports

Third Quarter 2020 Financial Results

 

HOUSTON – November 5, 2020 - Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported third quarter 2020 results.

 

Third Quarter 2020 Financial Results

 

Third quarter 2020 net income (loss) attributable to Targa Resources Corp. was $69.3 million compared to a net loss of $(47.3) million for the third quarter of 2019.

 

The Company reported quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $419.1 million for the third quarter of 2020 compared to $349.6 million for the third quarter of 2019 (see the section of this release entitled “Targa Resources Corp. ― Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, free cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

 

On October 15, 2020, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended September 30, 2020, or $0.40 per share on an annualized basis. Total cash dividends of approximately $23.3 million will be paid on November 16, 2020 on all outstanding shares of common stock to holders of record as of the close of business on October 30, 2020. Also, on October 15, 2020, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million will be paid on November 13, 2020 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on October 30, 2020.

 

The Company reported distributable cash flow and free cash flow before dividends for the third quarter of 2020 of $294.7 million and $189.3 million.

 

Third Quarter 2020 - Sequential Quarter over Quarter Commentary

 

Targa reported third quarter 2020 Adjusted EBITDA of $419.1 million, representing a 19 percent increase over the second quarter. The sequential increase in Adjusted EBITDA was attributable to an improved commodity price environment and the resumption of production from temporary curtailments and producer activity, predominantly across Targa’s Permian gathering and processing systems, which drove increasing volumes through Targa’s Logistics and Transportation (“L&T”) systems. Targa also benefited from partial quarter contributions from new assets placed in-service during the quarter, including its 250 million cubic feet per day (“MMcf/d”) Gateway Plant in Permian Midland, the phased expansion of its liquefied petroleum gas (“LPG”) export facilities in Galena Park, and its 110 thousand barrel per day (“MBbl/d”) fractionation Train 8 in Mont Belvieu. In the Gathering and Processing (“G&P”) segment, the sequential increase in segment gross margin was predominantly attributable to higher Permian natural gas inlet volumes, which increased 9 percent in the third quarter over the second quarter, and higher Permian fee-based margin. In the L&T segment, the sequential increase in gross margin was primarily attributable to strong Grand Prix Pipeline (“Grand Prix”) transportation throughput and higher LPG export volumes, combined with higher fractionation volumes and higher marketing margin. Third quarter Grand Prix volumes increased 18 percent sequentially, while Targa’s LPG export volumes achieved a record 9.5 million barrels per month during the quarter, increasing 22 percent over the second quarter. Third quarter fractionation volumes were impacted by scheduled maintenance, which resulted in Targa building inventory, shifting the timing of incremental volumes to be fractionated to the fourth quarter. Operating expenses were flat sequentially, despite the addition of new assets beginning operations during the third quarter across both the G&P and L&T segments.  

 

2020 Outlook

 

As previously disclosed, Targa estimates its full year 2020 Adjusted EBITDA to be at or around the high end of its previously provided outlook of $1.5 billion to $1.625 billion. Targa also estimates that its 2020 net growth capital spending to be around $700 million, and now estimates that its full year 2020 net maintenance capital to be approximately $110 million.

 


 


 

Third Quarter 2020 - Capitalization and Liquidity

 

The Company’s total consolidated debt as of September 30, 2020 was $7,914.1 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,479.1 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $48.5 million of debt issuance costs, with $100.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $250.0 million outstanding under TRP’s accounts receivable securitization facility, $7,145.0 million of outstanding TRP senior notes, net of unamortized premiums, and $32.6 million of finance lease liabilities.

 

Total consolidated liquidity of the Company as of September 30, 2020, including $275.0 million of cash, was approximately $2.6 billion. As of September 30, 2020, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $100.0 million of borrowings and $35.3 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $2,064.7 million.

 

Growth Projects Update

 

Since the beginning of 2020, the Company has completed substantially all of its major growth capital projects underway either on- or under-budget. Targa has commenced operations on its:

 

110 MBbl/d Train 7 fractionator in Mont Belvieu,

 

250 MMcf/d Peregrine Plant in Permian Delaware,

 

Phased expansion at its LPG export facility in Galena Park,

 

250 MMcf/d Gateway Plant in Permian Midland, and

 

110 MBbl/d Train 8 fractionator in Mont Belvieu.

 

Targa’s Grand Prix extension into Central Oklahoma is expected to be operational by the end of the fourth quarter of 2020. Targa announced today that it is relocating its existing 200 MMcf/d Longhorn cryogenic natural gas processing plant from North Texas to Permian Midland, where it will be renamed the Heim Plant, to accommodate anticipated production growth across its Permian Midland system.  Relocating the plant will provide the Company with significant capital savings. The 200 MMcf/d Heim Plant is expected to begin operations in the fourth quarter of 2021, with a total estimated capital cost of approximately $90 million.

 

Financing and Asset Sales

 

In August 2020, the Partnership issued $1.0 billion aggregate principal amount of 4⅞% Senior Notes due 2031, resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer and redemption payments for the Partnership’s $580 million principal outstanding amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility. The Company accepted for purchase all the notes that were validly tendered as of the early tender date and redeemed the remaining aggregate principal amount of the 6¾% Notes.

 

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

 

Targa continues to evaluate and execute asset sales to reduce leverage and focus on its core operations. In October 2020, the Company closed on the sale of its assets in Channelview, Texas for approximately $58 million.

 

Share Repurchase Update

 

In October 2020, the Company’s Board of Directors approved a share repurchase program (the “Share Repurchase Program”) for the repurchase of up to $500 million of its outstanding common stock. As of November 2, 2020, the Company has repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of approximately $74 million. There is approximately $426 million remaining under the authorized Share Repurchase Program.  

 

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 5, 2020 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/w5f4facw. 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,

 

 

 

 

 

 

 

 

 

 

2020

 

 

2019

 

 

2020 vs. 2019

 

 

2020

 

 

2019

 

 

2020 vs. 2019

 

 

(In millions)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

$

1,840.8

 

 

$

1,594.2

 

 

$

246.6

 

 

 

15

%

 

$

4,900.8

 

 

$

5,254.8

 

 

$

(354.0

)

 

 

(7

%)

Fees from midstream services

 

274.3

 

 

 

308.3

 

 

 

(34.0

)

 

 

(11

%)

 

 

786.7

 

 

 

942.4

 

 

 

(155.7

)

 

 

(17

%)

Total revenues

 

2,115.1

 

 

 

1,902.5

 

 

 

212.6

 

 

 

11

%

 

 

5,687.5

 

 

 

6,197.2

 

 

 

(509.7

)

 

 

(8

%)

Product purchases

 

1,303.2

 

 

 

1,328.1

 

 

 

(24.9

)

 

 

(2

%)

 

 

3,346.8

 

 

 

4,415.7

 

 

 

(1,068.9

)

 

 

(24

%)

Gross margin (1)

 

811.9

 

 

 

574.4

 

 

 

237.5

 

 

 

41

%

 

 

2,340.7

 

 

 

1,781.5

 

 

 

559.2

 

 

 

31

%

Operating expenses

 

181.9

 

 

 

200.2

 

 

 

(18.3

)

 

 

(9

%)

 

 

565.1

 

 

 

600.8

 

 

 

(35.7

)

 

 

(6

%)

Operating margin (1)

 

630.0

 

 

 

374.2

 

 

 

255.8

 

 

 

68

%

 

 

1,775.6

 

 

 

1,180.7

 

 

 

594.9

 

 

 

50

%

Depreciation and amortization expense

 

203.7

 

 

 

244.3

 

 

 

(40.6

)

 

 

(17

%)

 

 

647.3

 

 

 

718.9

 

 

 

(71.6

)

 

 

(10

%)

General and administrative expense

 

58.6

 

 

 

69.9

 

 

 

(11.3

)

 

 

(16

%)

 

 

180.6

 

 

 

223.5

 

 

 

(42.9

)

 

 

(19

%)

Impairment of long-lived assets

 

 

 

 

 

 

 

 

 

 

 

 

 

2,442.8

 

 

 

 

 

 

2,442.8

 

 

 

 

Other operating (income) expense

 

72.2

 

 

 

18.4

 

 

 

53.8

 

 

 

292

%

 

 

73.8

 

 

 

21.7

 

 

 

52.1

 

 

 

240

%

Income (loss) from operations

 

295.5

 

 

 

41.6

 

 

 

253.9

 

 

NM

 

 

 

(1,568.9

)

 

 

216.6

 

 

 

(1,785.5

)

 

NM

 

Interest expense, net

 

(97.7

)

 

 

(89.1

)

 

 

(8.6

)

 

 

(10

%)

 

 

(292.4

)

 

 

(241.8

)

 

 

(50.6

)

 

 

(21

%)

Equity earnings (loss)

 

18.6

 

 

 

10.0

 

 

 

8.6

 

 

 

86

%

 

 

54.1

 

 

 

15.9

 

 

 

38.2

 

 

 

240

%

Gain (loss) from financing activities

 

(13.7

)

 

 

 

 

 

(13.7

)

 

 

 

 

 

47.4

 

 

 

(1.4

)

 

 

48.8

 

 

NM

 

Gain (loss) from sale of equity-method investment

 

 

 

 

65.8

 

 

 

(65.8

)

 

 

(100

%)

 

 

 

 

 

65.8

 

 

 

(65.8

)

 

 

(100

%)

Change in contingent considerations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(8.8

)

 

 

8.8

 

 

 

100

%

Other, net

 

1.4

 

 

 

 

 

 

1.4

 

 

 

 

 

 

2.2

 

 

 

 

 

 

2.2

 

 

 

 

Income tax (expense) benefit

 

(31.9

)

 

 

3.8

 

 

 

(35.7

)

 

NM

 

 

 

286.6

 

 

 

10.0

 

 

 

276.6

 

 

NM

 

Net income (loss)

 

172.2

 

 

 

32.1

 

 

 

140.1

 

 

NM

 

 

 

(1,471.0

)

 

 

56.3

 

 

 

(1,527.3

)

 

NM

 

Less: Net income (loss) attributable to noncontrolling interests

 

102.9

 

 

 

79.4

 

 

 

23.5

 

 

 

30

%

 

 

116.5

 

 

 

152.7

 

 

 

(36.2

)

 

 

(24

%)

Net income (loss) attributable to Targa Resources Corp.

 

69.3

 

 

 

(47.3

)

 

 

116.6

 

 

 

247

%

 

 

(1,587.5

)

 

 

(96.4

)

 

 

(1,491.1

)

 

NM

 

Dividends on Series A Preferred Stock

 

22.9

 

 

 

22.9

 

 

 

 

 

 

 

 

 

68.8

 

 

 

68.8

 

 

 

 

 

 

 

Deemed dividends on Series A Preferred Stock

 

9.5

 

 

 

8.4

 

 

 

1.1

 

 

 

13

%

 

 

27.7

 

 

 

24.4

 

 

 

3.3

 

 

 

14

%

Net income (loss) attributable to common shareholders

$

36.9

 

 

$

(78.6

)

 

$

115.5

 

 

 

147

%

 

$

(1,684.0

)

 

$

(189.6

)

 

$

(1,494.4

)

 

NM

 

Financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (1)

$

419.1

 

 

$

349.6

 

 

$

69.5

 

 

 

20

%

 

$

1,198.5

 

 

$

970.3

 

 

$

228.2

 

 

 

24

%

Distributable cash flow (1)

 

294.7

 

 

 

229.9

 

 

 

64.8

 

 

 

28

%

 

 

878.9

 

 

 

619.4

 

 

 

259.5

 

 

 

42

%

Free cash flow (1)

 

189.3

 

 

 

(218.5

)

 

 

407.8

 

 

NM

 

 

 

360.4

 

 

 

(1,326.8

)

 

 

1,687.2

 

 

NM

 

 

(1)

Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”

NM

Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

 

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

 

The increase in commodity sales reflects higher natural gas liquid (“NGL”) and natural gas prices ($133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and the favorable impact of hedges ($171.0 million), partially offset by lower crude marketing and natural gas volumes ($128.9 million) and lower condensate and petroleum product prices ($29.6 million).

 

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

 

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

 

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

 

 


 

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

 

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

 

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 sale of such assets in October 2020 (the “October 2020 Sale”) and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

 

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

 

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

 

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

 

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

 

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

 

Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.

 

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

 

The decrease in commodity sales reflects lower NGL, condensate, natural gas and petroleum product prices ($1,112.5 million) and lower crude marketing volumes ($254.7 million), partially offset by higher NGL, condensate, natural gas and petroleum product volumes ($664.3 million), the favorable impact of hedges ($345.1 million) and higher crude marketing prices ($3.8 million).

 

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

 

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

 

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

 

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

 

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

 

 


 

The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems in the first quarter of 2020 associated with the Company's Mid-Continent operations and full impairment of the Company's Coastal operations - all of which are in the Company's Gathering and Processing segment. Based on then-current market conditions, the Company's first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. The Company did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019. The Company may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of the Company's long-lived assets and may result in future impairments.

 

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. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

 

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

 

The increase in equity earnings is primarily due to higher earnings from the Company's investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF.

 

During the nine months ended September 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest to repurchase $883.4 million of the notes, resulting in a $47.4 million net gain from financing activities.

 

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

 

The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act.

 

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses recognized during the first quarter of 2020 to noncontrolling interest holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands, LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture.

 

Review of Segment Performance

 

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

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

 

Gathering and Processing Segment

 

The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. 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,

 

 

 

 

 

 

 

 

 

 

 

2020

 

 

2019

 

 

2020 vs. 2019

 

 

2020

 

 

2019

 

 

2020 vs. 2019

 

 

(In millions, except operating statistics and price amounts)

 

Gross margin

$

 

362.9

 

 

$

 

366.7

 

 

$

 

(3.8

)

 

 

(1

%)

 

$

 

1,071.4

 

 

$

 

1,092.0

 

 

$

 

(20.6

)

 

 

(2

%)

Operating expenses

 

 

101.9

 

 

 

 

120.2

 

 

 

 

(18.3

)

 

 

(15

%)

 

 

 

317.7

 

 

 

 

375.2

 

 

 

 

(57.5

)

 

 

(15

%)

Operating margin

$

 

261.0

 

 

$

 

246.5

 

 

$

 

14.5

 

 

 

6

%

 

$

 

753.7

 

 

$

 

716.8

 

 

$

 

36.9

 

 

 

5

%

Operating statistics (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plant natural gas inlet, MMcf/d (2),(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

1,811.5

 

 

 

 

1,513.9

 

 

 

 

297.6

 

 

 

20

%

 

 

 

1,722.1

 

 

 

 

1,421.3

 

 

 

 

300.8

 

 

 

21

%

Permian Delaware

 

 

758.1

 

 

 

 

629.4

 

 

 

 

128.7

 

 

 

20

%

 

 

 

712.4

 

 

 

 

552.2

 

 

 

 

160.2

 

 

 

29

%

Total Permian

 

 

2,569.6

 

 

 

 

2,143.3

 

 

 

 

426.3

 

 

 

 

 

 

 

 

2,434.5

 

 

 

 

1,973.5

 

 

 

 

461.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX (5)

 

 

233.6

 

 

 

 

328.6

 

 

 

 

(95.0

)

 

 

(29

%)

 

 

 

261.5

 

 

 

 

335.3

 

 

 

 

(73.8

)

 

 

(22

%)

North Texas

 

 

197.8

 

 

 

 

228.2

 

 

 

 

(30.4

)

 

 

(13

%)

 

 

 

206.3

 

 

 

 

227.6

 

 

 

 

(21.3

)

 

 

(9

%)

SouthOK (6)

 

 

386.9

 

 

 

 

590.8

 

 

 

 

(203.9

)

 

 

(35

%)

 

 

 

463.3

 

 

 

 

606.1

 

 

 

 

(142.8

)

 

 

(24

%)

WestOK

 

 

233.6

 

 

 

 

329.2

 

 

 

 

(95.6

)

 

 

(29

%)

 

 

 

258.7

 

 

 

 

335.2

 

 

 

 

(76.5

)

 

 

(23

%)

Total Central

 

 

1,051.9

 

 

 

 

1,476.8

 

 

 

 

(424.9

)

 

 

 

 

 

 

 

1,189.8

 

 

 

 

1,504.2

 

 

 

 

(314.4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (7),(8)

 

 

137.0

 

 

 

 

120.8

 

 

 

 

16.2

 

 

 

13

%

 

 

 

136.1

 

 

 

 

103.4

 

 

 

 

32.7

 

 

 

32

%

Total Field

 

 

3,758.5

 

 

 

 

3,740.9

 

 

 

 

17.6

 

 

 

 

 

 

 

 

3,760.4

 

 

 

 

3,581.1

 

 

 

 

179.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

522.8

 

 

 

 

764.9

 

 

 

 

(242.1

)

 

 

(32

%)

 

 

 

672.9

 

 

 

 

779.9

 

 

 

 

(107.0

)

 

 

(14

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

4,281.3

 

 

 

 

4,505.8

 

 

 

 

(224.5

)

 

 

(5

%)

 

 

 

4,433.3

 

 

 

 

4,361.0

 

 

 

 

72.3

 

 

 

2

%

NGL production, MBbl/d (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

253.0

 

 

 

 

216.5

 

 

 

 

36.5

 

 

 

17

%

 

 

 

247.6

 

 

 

 

199.8

 

 

 

 

47.8

 

 

 

24

%

Permian Delaware

 

 

105.3

 

 

 

 

82.3

 

 

 

 

23.0

 

 

 

28

%

 

 

 

97.1

 

 

 

 

71.4

 

 

 

 

25.7

 

 

 

36

%

Total Permian

 

 

358.3

 

 

 

 

298.8

 

 

 

 

59.5

 

 

 

 

 

 

 

 

344.7

 

 

 

 

271.2

 

 

 

 

73.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX (5)

 

 

29.2

 

 

 

 

41.5

 

 

 

 

(12.3

)

 

 

(30

%)

 

 

 

28.7

 

 

 

 

44.0

 

 

 

 

(15.3

)

 

 

(35

%)

North Texas

 

 

23.7

 

 

 

 

27.3

 

 

 

 

(3.6

)

 

 

(13

%)

 

 

 

24.5

 

 

 

 

26.9

 

 

 

 

(2.4

)

 

 

(9

%)

SouthOK (6)

 

 

45.9

 

 

 

 

69.5

 

 

 

 

(23.6

)

 

 

(34

%)

 

 

 

54.6

 

 

 

 

65.4

 

 

 

 

(10.8

)

 

 

(17

%)

WestOK

 

 

19.3

 

 

 

 

19.2

 

 

 

 

0.1

 

 

 

1

%

 

 

 

21.2

 

 

 

 

22.4

 

 

 

 

(1.2

)

 

 

(5

%)

Total Central

 

 

118.1

 

 

 

 

157.5

 

 

 

 

(39.4

)

 

 

 

 

 

 

 

129.0

 

 

 

 

158.7

 

 

 

 

(29.7

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (8)

 

 

17.0

 

 

 

 

14.0

 

 

 

 

3.0

 

 

 

21

%

 

 

 

16.3

 

 

 

 

12.2

 

 

 

 

4.1

 

 

 

34

%

Total Field

 

 

493.4

 

 

 

 

470.3

 

 

 

 

23.1

 

 

 

 

 

 

 

 

490.0

 

 

 

 

442.1

 

 

 

 

47.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

32.5

 

 

 

 

45.4

 

 

 

 

(12.9

)

 

 

(28

%)