trgp-8k_20181108.htm

  

 

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 8, 2018

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))

 

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 8, 2018, Targa Resources Corp. (the “Company”) issued a press release regarding its financial results for the three months ended September 30, 2018. 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 8, 2018. 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, 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 8, 2018.

 

 

 

 

 

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 8, 2018

By:

/s/ Jennifer R. Kneale

 

 

Jennifer R. Kneale

 

 

Chief Financial Officer

(Principal Financial Officer)

 

trgp-ex991_7.htm

Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

 

Targa Resources Corp. Reports Third Quarter 2018 Financial Results

and Provides Update on Growth Projects, Financing and Longer-Term Outlook

 

HOUSTON – November 8, 2018 - Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported third quarter 2018 results.

 

Third Quarter 2018 Financial Results  

 

Third quarter 2018 net loss attributable to Targa Resources Corp. was ($23.7) million compared to ($167.6) million for the third quarter of 2017.

 

The Company reported record quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $358.0 million for the third quarter of 2018 compared to $276.5 million for the third quarter of 2017 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable 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”)).

 

“This is the strongest quarter in Targa’s history across multiple operational and financial dimensions, positioning us to exceed our full year 2018 financial guidance and providing Targa with positive momentum heading into 2019. With continued attractive business fundamentals, strong execution and multiple growth projects on-track to begin operations over the near term, Targa’s longer-term growth outlook continues to strengthen,” said Joe Bob Perkins, Chief Executive Officer of the Company.

 

On October 17, 2018, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended September 30, 2018, or $3.64 per share on an annualized basis. Total cash dividends of approximately $208.6 million will be paid on November 15, 2018 on all outstanding shares of common stock to holders of record as of the close of business on October 31, 2018. Also on October 17, 2018, TRC declared a quarterly cash dividend of $23.75 per share for its Series A Preferred Stock.  Total cash dividends of approximately $22.9 million will be paid on November 14, 2018 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on October 31, 2018.

 

The Company reported distributable cash flow for the third quarter of 2018 of $287.2 million compared to total common dividends to be paid of $208.6 million and total Series A Preferred Stock dividends to be paid of $22.9 million. In September 2018, the Company received the annual cash payment of $43 million under its long-term condensate splitter agreement, which is included in distributable cash flow for the third quarter.

 

Third Quarter 2018 - Capitalization and Liquidity

 

The Company’s total consolidated debt as of September 30, 2018 was $5,968.9 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $5,533.9 million of Targa Resources Partners LP (“TRP” or the “Partnership”) debt, net of $34.0 million of debt issuance costs, with $290.0 million outstanding under TRP’s accounts receivable securitization facility, $5,277.9 million of outstanding TRP senior unsecured notes and no borrowings outstanding under TRP’s $2.2 billion senior secured revolving credit facility.

 

Total consolidated liquidity of the Company as of September 30, 2018, including $203.2 million of cash, was approximately $2.6 billion. As of September 30, 2018, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $76.6 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 $2,123.4 million. In addition to the availability under its senior secured revolving credit facility, the Partnership also had $60.0 million of availability under its accounts receivable securitization facility.

 

Growth Projects Update

Today, Targa is announcing plans to construct two new 110 thousand barrels per day (“MBbl/d”) fractionation trains in Mont Belvieu, Texas, which are expected to begin operations in the first and second quarter of 2020, respectively.

 

 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

Targa now estimates 2018 net growth capital expenditures for announced projects will be approximately $2.4 billion and estimates that 2018 net maintenance capital expenditures will be approximately $110 million.

 

Targa also estimates that preliminary 2019 net growth capital expenditures for announced projects will be about $2 billion.

 

Financing Update

 

On September 12, 2018, Targa announced it had executed agreements to sell its refined products and crude oil storage and terminaling facilities in Tacoma, WA and Baltimore, MD to an affiliate of ArcLight Capital Partners, LLC for approximately $160 million. The sale closed on October 31, 2018. Targa intends to use the net proceeds to fund a portion of its growth capital program underway.

 

During the three months ended September 30, 2018, the Company issued 3,696,533 shares of common stock under its Equity Distribution Agreements (“EDAs”), resulting in total net proceeds of $202.4 million. For the nine months ended September 30, 2018, TRC has issued a total of 11,376,528 shares of common stock under its EDAs, resulting in total net proceeds of $572.0 million.

 

During the nine months ended September 30, 2018, Targa has raised approximately $1 billion in net proceeds from a combination of common stock sales, joint venture reimbursements and completed asset sales.

 

Today, Targa is also announcing it is evaluating the potential sale of a minority interest in its Badlands assets to a select small group of counterparties. Given the talented team of employees associated with the Badlands assets, the fee-based and long-term nature of the contracts, the strong performance of the assets, and the improving outlook in the Bakken, the Company believes that monetizing a minority interest would provide significant potential benefit to Targa while still retaining control over the operations and strategy of the business.

 

Updated Longer-Term Outlook

 

Today, Targa published a revised longer-term Adjusted EBITDA outlook and provided an aggregate preliminary estimate of net growth capital expenditures for 2020 through 2021 in its quarterly earnings supplement presentation and updated investor presentation available in the Events and Presentations section of the Company’s website at http://ir.targaresources.com/trc/events.cfm.  

 

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 8, 2018 to discuss third quarter 2018 results. The conference call can be accessed via webcast through the Events and Presentations section of Targa’s website at www.targaresources.com, by going directly to https://edge.media-server.com/m6/p/9gqo9sfy or by dialing 877-881-2598. The conference ID number for the dial-in is 9589340. Please dial in ten minutes prior to the scheduled start time. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

 


 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

Targa Resources Corp. – Consolidated Financial Results of Operations

 

 

Three Months Ended September 30,

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018 vs. 2017

 

2018

 

 

2017

 

 

2018 vs. 2017

 

 

 

 

(In millions, except operating statistics and price amounts)

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

$

2,654.1

 

 

$

1,871.5

 

 

$

782.6

 

 

 

42

%

$

6,981.4

 

 

$

5,353.1

 

 

$

1,628.3

 

 

 

30

%

 

 

Fees from midstream services

 

332.3

 

 

 

260.3

 

 

 

72.0

 

 

 

28

%

 

904.9

 

 

 

759.0

 

 

 

145.9

 

 

 

19

%

 

 

Total revenues

 

2,986.4

 

 

 

2,131.8

 

 

 

854.6

 

 

 

40

%

 

7,886.3

 

 

 

6,112.1

 

 

 

1,774.2

 

 

 

29

%

 

 

Product purchases

 

2,383.5

 

 

 

1,663.1

 

 

 

720.4

 

 

 

43

%

 

6,229.7

 

 

 

4,737.8

 

 

 

1,491.9

 

 

 

31

%

 

 

Gross margin (1)

 

602.9

 

 

 

468.7

 

 

 

134.2

 

 

 

29

%

 

1,656.6

 

 

 

1,374.3

 

 

 

282.3

 

 

 

21

%

 

 

Operating expenses

 

194.9

 

 

 

155.5

 

 

 

39.4

 

 

 

25

%

 

538.7

 

 

 

462.7

 

 

 

76.0

 

 

 

16

%

 

 

Operating margin (1)

 

408.0

 

 

 

313.2

 

 

 

94.8

 

 

 

30

%

 

1,117.9

 

 

 

911.6

 

 

 

206.3

 

 

 

23

%

 

 

Depreciation and amortization expense

 

206.3

 

 

 

208.3

 

 

 

(2.0

)

 

 

(1

%)

 

607.1

 

 

 

602.8

 

 

 

4.3

 

 

 

1

%

 

 

General and administrative expense

 

63.2

 

 

 

49.9

 

 

 

13.3

 

 

 

27

%

 

176.9

 

 

 

149.5

 

 

 

27.4

 

 

 

18

%

 

 

Impairment of property, plant and equipment

 

 

 

 

378.0

 

 

 

(378.0

)

 

 

(100

%)

 

 

 

 

378.0

 

 

 

(378.0

)

 

 

(100

%)

 

 

Other operating (income) expense

 

61.8

 

 

 

0.6

 

 

 

61.2

 

 

NM

 

 

15.7

 

 

 

17.2

 

 

 

(1.5

)

 

 

(9

%)

 

 

Income (loss) from operations

 

76.7

 

 

 

(323.6

)

 

 

400.3

 

 

 

124

%

 

318.2

 

 

 

(235.9

)

 

 

554.1

 

 

 

235

%

 

 

Interest expense, net

 

(78.2

)

 

 

(56.1

)

 

 

(22.1

)

 

 

39

%

 

(124.2

)

 

 

(181.2

)

 

 

57.0

 

 

 

31

%

 

 

Equity earnings (loss)

 

3.0

 

 

 

0.2

 

 

 

2.8

 

 

NM

 

 

6.4

 

 

 

(16.6

)

 

 

23.0

 

 

 

139

%

 

 

Gain (loss) from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

(2.0

)

 

 

(16.5

)

 

 

14.5

 

 

 

88

%

 

 

Change in contingent considerations

 

(16.6

)

 

 

126.8

 

 

 

(143.4

)

 

 

(113

%)

 

(12.1

)

 

 

125.6

 

 

 

(137.7

)

 

 

(110

%)

 

 

Other income (expense), net

 

 

 

 

0.2

 

 

 

(0.2

)

 

 

(100

%)

 

 

 

 

(2.7

)

 

 

2.7

 

 

 

100

%

 

 

Income tax (expense) benefit

 

3.9

 

 

 

97.4

 

 

 

(93.5

)

 

 

(96

%)

 

(37.7

)

 

 

132.3

 

 

 

(170.0

)

 

 

(128

%)

 

 

Net income (loss)

 

(11.2

)

 

 

(155.1

)

 

 

143.9

 

 

 

93

%

 

148.6

 

 

 

(195.0

)

 

 

343.6

 

 

 

176

%

 

 

Less: Net income (loss) attributable to noncontrolling interests

 

12.5

 

 

 

12.5

 

 

 

 

 

 

 

 

40.4

 

 

 

34.3

 

 

 

6.1

 

 

 

18

%

 

 

Net income (loss) attributable to Targa Resources Corp.

 

(23.7

)

 

 

(167.6

)

 

 

143.9

 

 

 

86

%

 

108.2

 

 

 

(229.3

)

 

 

337.5

 

 

 

147

%

 

 

Dividends on Series A Preferred Stock

 

22.9

 

 

 

22.9

 

 

 

 

 

 

 

 

68.8

 

 

 

68.8

 

 

 

 

 

 

 

 

 

Deemed dividends on Series A Preferred Stock

 

7.4

 

 

 

6.5

 

 

 

0.9

 

 

 

14

%

 

21.5

 

 

 

19.0

 

 

 

2.5

 

 

 

13

%

 

 

Net income (loss) attributable to common shareholders

$

(54.0

)

 

$

(197.0

)

 

$

143.0

 

 

 

73

%

$

17.9

 

 

$

(317.1

)

 

$

335.0

 

 

 

106

%

 

 

Financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (1)

$

358.0

 

 

$

276.5

 

 

$

81.5

 

 

 

29

%

$

990.6

 

 

$

811.1

 

 

$

179.5

 

 

 

22

%

 

 

Distributable cash flow (1)

 

287.2

 

 

 

186.6

 

 

 

100.6

 

 

 

54

%

 

728.5

 

 

 

576.7

 

 

 

151.8

 

 

 

26

%

 

 

Capital expenditures (2)

 

1,017.7

 

 

 

378.7

 

 

 

639.0

 

 

 

169

%

 

2,310.4

 

 

 

987.7

 

 

 

1,322.7

 

 

 

134

%

 

 

Business acquisition (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

987.1

 

 

 

(987.1

)

 

 

(100

%)

 

 

 

(1)

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

(2)

Capital expenditures, net of contributions from noncontrolling interest, were $856.8 million and $1,890.8 million for the three and nine months ended September 30, 2018, and $344.4 million and $889.3 million for the three and nine months ended September 30, 2017.

(3)

Includes the $416.3 million acquisition date fair value of the potential earn-out payments.

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, 2018 Compared to Three Months Ended September 30, 2017

 

The increase in commodity sales reflects increased NGL, natural gas, condensate and petroleum volumes ($538.4 million) and higher NGL and condensate prices ($475.5 million), partially offset by lower natural gas prices ($127.5 million) and the impact of hedges ($21.4 million). Fee-based and other revenues increased primarily due to higher gas processing and crude gathering fees.

 

The increase in product purchases reflects increased volumes and higher NGL and condensate prices.

 

 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($84.6 million) and lower fee revenue ($5.8 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin.

 

The higher operating margin and gross margin in 2018 reflect increased segment margin results for Gathering and Processing and Logistics and Marketing. Additionally, the Company’s operating margin for the three months ended September 30, 2017 was reduced by approximately $10 million due to temporary operational issues related to the impact of Hurricane Harvey. Operating expenses increased compared to 2017 primarily due to system expansions and higher activity levels. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

 

Depreciation and amortization expense was flat as higher depreciation related to the Company’s growth investments was offset by lower depreciation for the Company’s North Texas system and lower scheduled amortization of Badlands intangibles. Lower North Texas system depreciation reflects the impact of a partial impairment of property, plant and equipment recorded in the third quarter of 2017.

 

General and administrative expense increased primarily due to higher compensation and benefits and higher outside professional services.

 

Other operating (income) expense in 2018 was comprised primarily of the estimated loss on the Company’s refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland that were held for sale as of September 30, 2018.

 

Interest expense, net, increased due to the impact of higher average borrowings and lower interest income on the mandatorily redeemable preferred interest valuations, partially offset by higher capitalized interest related to the Company’s major growth investments.

 

Equity earnings increased in 2018, primarily reflecting increased earnings at Gulf Coast Fractionators LP (“GCF”) and commencement of operations at the Cayenne Pipeline joint venture (“Cayenne”).

 

During 2018, the Company recorded expense of $16.6 million resulting primarily from an increase in fair value as of September 30, 2018 of the Permian Acquisition contingent consideration liability. The fair value increase in 2018 was primarily attributable to a shorter discount period. During 2017, the Company recorded income of $126.8 million resulting from a decrease in the fair value of the contingent consideration liability from June 30, 2017 to September 30, 2017. The fair value decrease in 2017 reflected reductions in actual and forecasted volumes and gross margin resulting from changes in producers’ drilling activity in the region.

 

The Company recorded a lower income tax benefit in 2018 than in 2017. The decrease is primarily attributable to the difference in income (loss) before taxes between the periods, the reduced statutory rate, and the difference in methods required by the interim tax accounting rules. In 2018, the Company determined income tax expense (benefit) using the estimated annual effective tax rate. However, in 2017, the application of interim tax accounting rules required the Company to use the then statutory tax rate for the nine-month period ended September 30, 2017 and the six-month period ended June 30, 2017. Furthermore, the Tax Cut and Jobs Act reduced the Federal statutory rate from 35% in 2017 to 21% in 2018.

 

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

 

The increase in commodity sales reflects increased NGL, natural gas, petroleum and condensate volumes ($1,241.7 million) and higher NGL and condensate prices ($1,097.5 million), partially offset by lower natural gas prices ($389.2 million) and the impact of hedges ($68.7 million). Fee-based and other revenues increased primarily due to higher gas processing and crude gathering fees.

 

The increase in product purchases reflects increased volumes and higher NGL and condensate prices.

 

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($250.6 million) and lower fee revenue ($18.6 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin.

 

 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

The higher operating margin and gross margin in 2018 reflect increased segment margin results for Gathering and Processing and Logistics and Marketing. Additionally, the Company’s operating margin for the nine months ended September 30, 2017 was reduced by approximately $10 million due to temporary operational issues related to the impact of Hurricane Harvey. Operating expenses increased compared to 2017 primarily due to system expansions, higher activity levels and the inclusion of the Permian Acquisition for nine months in 2018 as compared with seven months in 2017. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

 

Depreciation and amortization expense was flat as higher depreciation related to the Company’s growth investments was offset by lower depreciation for the Company’s North Texas system, lower scheduled amortization of Badlands intangibles and lower depreciation on the Company’s inland marine barge business sold in the second quarter of 2018. In 2017, the Company recorded a partial impairment of property, plant and equipment in the Company’s North Texas system.

 

General and administrative expense increased primarily due to higher compensation and benefits and higher outside professional services.

 

Other operating (income) expense in 2018 was comprised primarily of the estimated loss on the Company’s refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, that were held for sale as of September 30, 2018, partially offset by the gain on sale of the Company’s inland marine barge business. In 2017, other operating (income) expense included the loss on sale of the Company’s 100% ownership interest in the Venice Gathering System.

 

Lower interest expense, net, in 2018 was primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interests liability and higher capitalized interest related to the Company’s major growth investments. These factors more than offset the impact of higher average outstanding borrowings during 2018. The mandatorily redeemable preferred interests liability is revalued quarterly at the estimated redemption value as of the reporting date, and the decrease in 2018 of its estimated redemption value is primarily attributable to the February 2018 amendments to the agreements governing the WestTX and WestOK joint ventures.

 

Equity earnings increased in 2018, which reflects decreased losses of the T2 Joint Ventures, which in 2017 included a $12.0 million loss provision due to the impairment of the Company’s investment in the T2 EF Cogen joint venture, increased earnings at GCF and the commencement of operations at Cayenne.

 

In 2018, the Company recorded a loss from financing activities of $2.0 million associated with amendments to the Company’s revolving credit facilities, which resulted in a write-off of debt issuance costs. In 2017, the Company recorded a loss from financing activities of $16.5 million on the redemption of the outstanding 6⅜% Senior Notes and the repayment of the outstanding balance on the Company’s senior secured term loan.

 

During 2018, the Company recorded expense of $12.1 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the increase in fair value as of September 30, 2018 of the Permian Acquisition contingent consideration liability described above. During 2017, the Company recorded income of $125.6 million resulting from a decrease in the fair value of the Permian Acquisition contingent consideration liability from the acquisition date to September 30, 2017.

 

During 2018, the Company recorded income tax expense, whereas in 2017 the Company recorded an income tax benefit. Similar to the quarterly results, the change is primarily attributable to the difference in income (loss) before taxes between the periods, the reduced federal statutory rate from 2017 to 2018 and the difference in methods required by the interim tax accounting rules. As described above in the quarterly results, the Company utilized the estimated annual effective tax rate in 2018, whereas in 2017 the Company used the then statutory rate of 37.3% due to the loss limitation rule under interim period income tax accounting.

 

Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Company’s consolidated Carnero joint venture and Cedar Bayou Fractionators.

 

Review of Segment Performance

 

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin as an important performance measure of the core profitability of its operations. This measure is a key component of internal financial reporting and is reviewed for consistency and trend analysis. For a discussion of operating margin, see “Targa Resources Corp. - Non-GAAP Financial Measures - Operating Margin.” Segment operating financial results and operating statistics include the effects of

 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

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 Marketing.

 

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 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 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 exposure to the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

 

 


Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

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,

 

 

 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018 vs. 2017

 

 

2018

 

 

2017

 

 

 

2018  vs. 2017

 

Gross margin

$

 

373.7

 

 

$

 

289.7

 

 

$

 

84.0

 

 

 

29

%

 

$

 

1,046.3

 

 

$

 

817.1

 

 

$

 

229.2

 

 

 

28

%

Operating expenses

 

 

118.4

 

 

 

 

91.4

 

 

 

 

27.0

 

 

 

30

%

 

 

 

327.9

 

 

 

 

267.8

 

 

 

 

60.1

 

 

 

22

%

Operating margin

$

 

255.3

 

 

$

 

198.3

 

 

$

 

57.0

 

 

 

29

%

 

$

 

718.4

 

 

$

 

549.3

 

 

$

 

169.1

 

 

 

31

%

Operating statistics (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

1,161.7

 

 

 

 

932.1

 

 

 

 

229.6

 

 

 

25

%

 

 

 

1,100.8

 

 

 

 

864.9

 

 

 

 

235.9

 

 

 

27

%

Permian Delaware (4)

 

 

470.5

 

 

 

 

403.9

 

 

 

 

66.6

 

 

 

16

%

 

 

 

432.5

 

 

 

 

373.6

 

 

 

 

58.9

 

 

 

16

%

Total Permian

 

 

1,632.2

 

 

 

 

1,336.0

 

 

 

 

296.2

 

 

 

 

 

 

 

 

1,533.3

 

 

 

 

1,238.5

 

 

 

 

294.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

364.1

 

 

 

 

330.1

 

 

 

 

34.0

 

 

 

10

%

 

 

 

397.8

 

 

 

 

242.1

 

 

 

 

155.7

 

 

 

64

%

North Texas

 

 

247.6

 

 

 

 

261.8

 

 

 

 

(14.2

)

 

 

(5

%)

 

 

 

243.0

 

 

 

 

273.7

 

 

 

 

(30.7

)

 

 

(11

%)

SouthOK

 

 

568.2

 

 

 

 

515.2

 

 

 

 

53.0

 

 

 

10

%

 

 

 

549.4

 

 

 

 

478.5

 

 

 

 

70.9

 

 

 

15

%

WestOK

 

 

353.9

 

 

 

 

367.1

 

 

 

 

(13.2

)

 

 

(4

%)

 

 

 

350.8

 

 

 

 

382.5

 

 

 

 

(31.7

)

 

 

(8

%)

Total Central

 

 

1,533.8

 

 

 

 

1,474.2

 

 

 

 

59.6

 

 

 

 

 

 

 

 

1,541.0

 

 

 

 

1,376.8

 

 

 

 

164.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (5)

 

 

90.5

 

 

 

 

60.9

 

 

 

 

29.6

 

 

 

49

%

 

 

 

83.3

 

 

 

 

53.1

 

 

 

 

30.2

 

 

 

57

%

Total Field

 

 

3,256.5

 

 

 

 

2,871.1

 

 

 

 

385.4

 

 

 

 

 

 

 

 

3,157.6

 

 

 

 

2,668.4

 

 

 

 

489.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

783.3

 

 

 

 

750.5

 

 

 

 

32.8

 

 

 

4

%

 

 

 

724.5

 

 

 

 

750.1

 

 

 

 

(25.6

)

 

 

(3

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

4,039.8

 

 

 

 

3,621.6

 

 

 

 

418.2

 

 

 

12

%

 

 

 

3,882.1

 

 

 

 

3,418.5

 

 

 

 

463.6

 

 

 

14

%

NGL production, MBbl/d (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

152.2

 

 

 

 

122.8

 

 

 

 

29.4

 

 

 

24

%

 

 

 

148.0

 

 

 

 

111.8

 

 

 

 

36.2

 

 

 

32

%

Permian Delaware (4)

 

 

58.9

 

 

 

 

46.3

 

 

 

 

12.6

 

 

 

27

%

 

 

 

51.6

 

 

 

 

42.4

 

 

 

 

9.2

 

 

 

22

%

Total Permian

 

 

211.1

 

 

 

 

169.1

 

 

 

 

42.0

 

 

 

 

 

 

 

 

199.6

 

 

 

 

154.2

 

 

 

 

45.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

49.0

 

 

 

 

35.4

 

 

 

 

13.6

 

 

 

38

%

 

 

 

52.5

 

 

 

 

25.2

 

 

 

 

27.3

 

 

 

108

%

North Texas

 

 

29.6

 

 

 

 

29.3

 

 

 

 

0.3

 

 

 

1

%

 

 

 

28.1

 

 

 

 

30.8

 

 

 

 

(2.7

)

 

 

(9

%)

SouthOK

 

 

61.2

 

 

 

 

42.7

 

 

 

 

18.5

 

 

 

43

%

 

 

 

53.8

 

 

 

 

40.7

 

 

 

 

13.1

 

 

 

32

%

WestOK

 

 

20.7

 

 

 

 

20.7

 

 

 

 

-

 

 

 

-

 

 

 

 

19.9

 

 

 

 

22.3

 

 

 

 

(2.4

)

 

 

(11

%)

Total Central

 

 

160.5

 

 

 

 

128.1

 

 

 

 

32.4

 

 

 

 

 

 

 

 

154.3

 

 

 

 

119.0

 

 

 

 

35.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

10.5

 

 

 

 

9.0

 

 

 

 

1.5

 

 

 

17

%

 

 

 

10.5

 

 

 

 

7.4

 

 

 

 

3.1

 

 

 

42

%

Total Field

 

 

382.1

 

 

 

 

306.2

 

 

 

 

75.9

 

 

 

 

 

 

 

 

364.4

 

 

 

 

280.6

 

 

 

 

83.8