trgp-8k_20190220.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):

February 20, 2019

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 February 20, 2019, Targa Resources Corp. (the “Company”) issued a press release regarding its financial results for the three months and year ended December 31, 2018. A conference call to discuss these results is scheduled for 11:00 a.m. Eastern time (10:00 a.m. Central time) on Wednesday, February 20, 2019. 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 February 20, 2019.

 

 

 

 

 

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: February 20, 2019

By:

/s/ Jennifer R. Kneale

 

 

Jennifer R. Kneale

 

 

Chief Financial Officer

(Principal Financial Officer)

 

trgp-ex991_34.htm

Exhibit 99.1

 

 

811 Louisiana, Suite 2100

Houston, TX 77002

713.584.1000

 

Targa Resources Corp. Reports

Fourth Quarter and Full Year 2018 Financial Results and Provides 2019 Operational and Financial Guidance

 

HOUSTON – February 20, 2019 - Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2018 results.

 

Fourth Quarter and Full Year 2018 Financial Results

 

Fourth quarter 2018 net income (loss) attributable to Targa Resources Corp. was ($106.4) million compared to $283.1 million for the fourth quarter of 2017. The fourth quarter of 2018 included a pre-tax non-cash loss of $210.0 million from the impairment of goodwill. For the full year 2018, net income attributable to Targa Resources Corp. was $1.6 million compared to $54.0 million for 2017.

 

The Company reported earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $375.8 million for the fourth quarter of 2018 compared to $328.4 million for the fourth quarter of 2017. For the full year 2018, Adjusted EBITDA was $1,366.3 million compared to $1,139.8 million for 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”)).

 

“The strength of our execution and performance during 2018 drove record Adjusted EBITDA, providing Targa with positive momentum for 2019 and beyond,” said Joe Bob Perkins, Chief Executive Officer of the Company. “Key projects are coming online for us in 2019, including additional Gathering and Processing facilities, another fractionator in Mont Belvieu, Texas, and our Grand Prix NGL Pipeline, which will connect much of our G&P NGL supply to Mont Belvieu. These projects are all expected to be highly utilized as we continue to support the needs of our customers, and will drive increasing, largely fee-based, cash flow growth for Targa. We remain focused on execution to enhance our already attractive long-term outlook.”

 

On January 17, 2019, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended December 31, 2018, or $3.64 per share on an annualized basis. Total cash dividends of approximately $211.2 million were paid on February 15, 2019 on all outstanding shares of common stock to holders of record as of the close of business on January 31, 2019. Also on January 17, 2019, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million were paid on February 14, 2019 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on January 31, 2019.

 

The Company reported distributable cash flow for the fourth quarter of 2018 of $214.0 million compared to total common dividends to be paid of $211.2 million and total Series A Preferred Stock dividends to be paid of $22.9 million. For the full year 2018, distributable cash flow of $942.4 million resulted in dividend coverage over 1.0 times on the common and Series A Preferred Stock dividends paid with respect to 2018.

 

Capitalization and Liquidity

 

The Company’s total consolidated debt as of December 31, 2018 was $6,660.3 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $6,225.3 million of Targa Resources Partners LP (“TRP” or “the Partnership”) debt, net of $32.6 million of debt issuance costs, with $700.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $280.0 million outstanding under TRP’s accounts receivable securitization facility and $5,277.9 million of outstanding TRP senior notes, net of unamortized premiums.

 

Total consolidated liquidity of the Company as of December 31, 2018, including $232.1 million of cash, was over $1.9 billion. As of December 31, 2018, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $79.5 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $1,420.5 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.

 

 

 

 

 

 


 

Financing Update

 

During the three months ended December 31, 2018, the Company issued 2,467,085 shares of common stock under its equity distribution agreements (“EDAs”), resulting in total net proceeds of $111.5 million. For the year ended December 31, 2018, TRC issued a total of 13,843,613 shares of common stock under its EDAs, resulting in total net proceeds of $683.5 million.

 

On December 7, 2018, TRC amended and extended the Partnership’s accounts receivable securitization facility to increase the facility size from $350.0 million to $400.0 million and extend the maturity date to December 6, 2019.

 

In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,488.8 million. The net proceeds from the offerings were used to redeem in full the Partnership’s outstanding senior notes due 2019 and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions, and working capital.

 

In February 2019, the Company entered into definitive agreements to sell a 45 percent interest in Targa Badlands LLC (“Badlands”), the entity that holds all of the Company’s assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for $1.6 billion in cash.

 

The Company expects to use the net cash proceeds to pay down debt and for general corporate purposes including funding its growth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions.

  

2019 Financial and Operational Expectations

 

For 2019, assuming NGL composite barrel prices average $0.60 per gallon, crude oil prices average $54 per barrel and natural gas prices average $3.00 per MMbtu for the year, and pro forma for its recently announced transaction to sell a 45 percent interest in the Badlands, Targa estimates full year Adjusted EBITDA to be between $1,300 million and $1,400 million.

 

Targa estimates 2019 net growth capital expenditures to be approximately $2.3 billion, based on currently announced projects and other identified spending. Net maintenance capital expenditures for 2019 are estimated to be approximately $130 million.

 

Targa estimates that 2019 Field Gathering and Processing (“G&P”) natural gas inlet volumes will average between 3,450 million cubic feet per day (“MMcf/d”) and 3,650 MMcf/d, with the midpoint representing a 10 percent increase over 2018 Field G&P average natural gas inlet volumes. In the Permian Basin, Targa estimates average G&P natural gas inlet volumes will be between 1,850 MMcf/d and 1,950 MMcf/d, with the midpoint representing a 20 percent increase over 2018 Permian G&P average natural gas inlet volumes. In the Badlands and SouthOK, Targa estimates 2019 average natural gas inlet volumes will be higher than average 2018 volumes, and Targa also estimates higher average crude gathered volumes in both the Badlands and Permian year over year. Targa estimates that these volume increases will be partially offset by lower volumes in WestOK, SouthTX and North Texas.

 

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 February 20, 2019 to discuss fourth quarter 2018 results and its 2019 operational and financial outlook. 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/ui7iq2dg or by dialing 877-881-2598. The conference ID number for the dial-in is 2176547. 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.

 

 


 

Targa Resources Corp. – Consolidated Financial Results of Operations

 

 

 

Three Months Ended

December 31,

 

 

 

 

 

 

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018 vs. 2017

 

 

2018

 

 

2017

 

 

2018 vs. 2017

 

 

(In millions, except operating statistics and price amounts)

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

$

2,297.4

 

 

$

2,398.0

 

 

$

(100.6

)

 

(4

%)

 

$

9,278.7

 

 

$

7,751.1

 

 

$

1,527.6

 

 

20

%

Fees from midstream services

 

300.4

 

 

 

304.8

 

 

 

(4.4

)

 

(1

%)

 

 

1,205.3

 

 

 

1,063.8

 

 

 

141.5

 

 

13

%

Total revenues

 

2,597.8

 

 

 

2,702.8

 

 

 

(105.0

)

 

(4

%)

 

 

10,484.0

 

 

 

8,814.9

 

 

 

1,669.1

 

 

19

%

Product purchases

 

2,008.6

 

 

 

2,168.2

 

 

 

(159.8

)

 

(7

%)

 

 

8,238.2

 

 

 

6,906.1

 

 

 

1,332.1

 

 

19

%

Gross margin (1)

 

589.2

 

 

 

534.6

 

 

 

54.6

 

 

10

%

 

 

2,245.8

 

 

 

1,908.8

 

 

 

337.0

 

 

18

%

Operating expenses

 

183.3

 

 

 

160.2

 

 

 

23.1

 

 

14

%

 

 

722.0

 

 

 

622.9

 

 

 

99.1

 

 

16

%

Operating margin (1)

 

405.9

 

 

 

374.4

 

 

 

31.5

 

 

8

%

 

 

1,523.8

 

 

 

1,285.9

 

 

 

237.9

 

 

19

%

Depreciation and amortization expense

 

208.7

 

 

 

206.7

 

 

 

2.0

 

 

1

%

 

 

815.9

 

 

 

809.5

 

 

 

6.4

 

 

1

%

General and administrative expense

 

80.0

 

 

 

54.0

 

 

 

26.0

 

 

48

%

 

 

256.9

 

 

 

203.4

 

 

 

53.5

 

 

26

%

Impairment of property, plant and equipment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

378.0

 

 

 

(378.0

)

 

(100

%)

Impairment of goodwill

 

210.0

 

 

 

 

 

 

210.0

 

 

 

 

 

210.0

 

 

 

 

 

 

210.0

 

 

 

Other operating (income) expense

 

(12.2

)

 

 

0.2

 

 

 

(12.4

)

NM

 

 

 

3.5

 

 

 

17.4

 

 

 

(13.9

)

 

(80

%)

Income (loss) from operations

 

(80.6

)

 

 

113.5

 

 

 

(194.1

)

 

(171

%)

 

 

237.5

 

 

 

(122.4

)

 

 

359.9

 

 

294

%

Interest expense, net

 

(61.6

)

 

 

(52.4

)

 

 

(9.2

)

 

(18

%)

 

 

(185.8

)

 

 

(233.7

)

 

 

47.9

 

 

20

%

Equity earnings (loss)

 

0.9

 

 

 

(0.3

)

 

 

1.2

 

NM

 

 

 

7.3

 

 

 

(17.0

)

 

 

24.3

 

 

143

%

Gain (loss) from financing activities

 

 

 

 

(0.3

)

 

 

0.3

 

 

100

%

 

 

(2.0

)

 

 

(16.8

)

 

 

14.8

 

 

88

%

Change in contingent considerations

 

20.9

 

 

 

(26.0

)

 

 

46.9

 

 

180

%

 

 

8.8

 

 

 

99.6

 

 

 

(90.8

)

 

(91

%)

Other income (expense), net

 

0.1

 

 

 

(0.1

)

 

 

0.2

 

 

200

%

 

 

0.1

 

 

 

(2.6

)

 

 

2.7

 

 

104

%

Income tax (expense) benefit

 

32.3

 

 

 

264.8

 

 

 

(232.5

)

 

(88

%)

 

 

(5.5

)

 

 

397.1

 

 

 

(402.6

)

 

(101

%)

Net income (loss)

 

(88.0

)

 

 

299.2

 

 

 

(387.2

)

 

(129

%)

 

 

60.4

 

 

 

104.2

 

 

 

(43.8

)

 

(42

%)

Less: Net income (loss) attributable to noncontrolling interests

 

18.4

 

 

 

16.1

 

 

 

2.3

 

 

14

%

 

 

58.8

 

 

 

50.2

 

 

 

8.6

 

 

17

%

Net income (loss) attributable to Targa Resources Corp.

 

(106.4

)

 

 

283.1

 

 

 

(389.5

)

 

(138

%)

 

 

1.6

 

 

 

54.0

 

 

 

(52.4

)

 

(97

%)

Dividends on Series A Preferred Stock

 

22.9

 

 

 

22.9

 

 

 

 

 

 

 

 

91.7

 

 

 

91.7

 

 

 

 

 

 

Deemed dividends on Series A Preferred Stock

 

7.7

 

 

 

6.7

 

 

 

1.0

 

 

15

%

 

 

29.2

 

 

 

25.7

 

 

 

3.5

 

 

14

%

Net income (loss) attributable to common shareholders

$

(137.0

)

 

$

253.5

 

 

$

(390.5

)

 

(154

%)

 

$

(119.3

)

 

$

(63.4

)

 

$

(55.9

)

 

(88

%)

Financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (1)

$

375.8

 

 

$

328.4

 

 

$

47.4

 

 

14

%

 

$

1,366.3

 

 

$

1,139.8

 

 

$

226.5

 

 

20

%

Distributable cash flow (1)

 

214.0

 

 

 

274.6

 

 

 

(60.6

)

 

(22

%)

 

 

942.4

 

 

 

851.8

 

 

 

90.6

 

 

11

%

Capital expenditures (2)

 

1,017.3

 

 

 

518.9

 

 

 

498.4

 

 

96

%

 

 

3,327.7

 

 

 

1,506.5

 

 

 

1,821.2

 

 

121

%

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 $2,740.7 million, and $1,441.5 million for the years ended December 31, 2018 and 2017, and $624.2 million and $518.8 million for the three months ended December 31, 2018 and 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 December 31, 2018 Compared to Three Months Ended December 31, 2017

 

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($405.7 million) and decreased petroleum volumes ($17.2 million), partially offset by increased NGL, condensate and natural gas volumes ($358.0 million) and the impact of hedges ($46.2 million). Fee-based and other revenues were relatively flat.

 

The decrease in product purchases was primarily due to lower commodity prices and the effect of prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018, partially offset by increased volumes.  

 

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($82.6 million) and lower fee revenue ($21.0 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 results for the Gathering and Processing segment. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

 

 


 

Depreciation and amortization expense increased due to higher depreciation related to the Company’s growth investments, partially offset by lower scheduled amortization of Badlands intangibles and lower depreciation due to asset sales in 2018.

 

General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, and higher outside professional services.

 

In conjunction with the Company’s required annual goodwill assessments, the Company recognized impairments of goodwill totaling $210.0 million during 2018 related to the remaining goodwill from the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values.

 

Other operating (income) expense in 2018 was comprised primarily of the gain on an exchange of a portion of the Company’s Versado gathering system, partially offset by the loss on disposal of the benzene saturation component of the Company’s LSNG hydrotreater and the loss for abandoned project development costs. There was no such activity in 2017.

 

Higher interest expense, net, in 2018 was primarily due to higher average outstanding borrowings and higher average interest rates during 2018, partially offset by higher capitalized interest related to the Company’s major growth investments.

 

During 2018, the Company recorded other income of $20.9 million primarily related to decreases in the fair value of the Permian Acquisition contingent consideration liability. During 2017, the Company recorded other expense of $26.0 million primarily related to increases in the fair value of the Permian Acquisition contingent consideration liability.

 

The decrease in the income tax benefit in 2018 is primarily due to the recalculation of deferred balances as a result of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”), which reduced the corporate tax rate from 35% to 21%.  The benefit of the rate reduction was included in the 2017 income tax benefit.

 

Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Company’s consolidated Centrahoma joint venture.

 

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

 

The increase in commodity sales reflects increased NGL, natural gas, petroleum and condensate volumes ($1,606.0 million) and higher NGL and condensate prices ($742.2 million), partially offset by lower natural gas prices ($465.7 million) and the impact of hedges ($22.4 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.

 

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($333.2 million) and lower fee revenue ($39.6 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 results for both Gathering and Processing and Logistics and Marketing. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

 

Depreciation and amortization expense increased due to higher depreciation related to the Company’s growth investments, partially offset by lower depreciation for the Company’s North Texas system, which incurred an impairment write-down in 2017, lower scheduled amortization of Badlands intangibles and lower depreciation on the Company’s inland marine barge business sold in the second quarter of 2018.

 

General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, legal costs, outside professional services and contract labor costs.

 

In conjunction with the Company’s required annual goodwill assessments, the Company recognized impairments of goodwill totaling $210.0 million during 2018 related to the remaining goodwill from the Atlas mergers. There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values.

 

 


 

Other operating (income) expense in 2018 was comprised primarily of the loss on sale of the Company’s refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, the loss on disposal of the benzene saturation component of the Company’s LSNG hydrotreater and the loss for abandoned project development costs, partially offset by the gain on sale of the Company’s inland marine barge business and the gain on an exchange of a portion of the Company’s Versado gathering system. 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 lower valuation of 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.

 

Equity earnings increased in 2018 primarily due to decreased losses of the T2 Joint Ventures, increased earnings resulting from the commencement of operations at Cayenne and increased earnings at Gulf Coast Fractionators. Equity losses of the T2 Joint Ventures in 2017 included a $12.0 million impairment of the Company’s investment in the T2 EF Cogen joint venture.

 

In 2018, the Company recorded a loss from financing activities of $2.0 million associated with amendments of 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 $16.8 million upon the redemption of the Partnership’s outstanding 6⅜% Senior Notes and the repayment of the outstanding balance on the Company’s senior secured term loan.

 

During 2018, other income included $8.8 million of fair value adjustments of the Permian Acquisition contingent consideration, as compared to $99.6 million of other income in 2017. The decrease in fair value of the contingent consideration in 2018 was primarily attributable to lower forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discount period. The decrease in fair value of the contingent consideration in 2017 was primarily related to reductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region.

 

During 2018, the Company recorded income tax expense, whereas in 2017 the Company recorded an income tax benefit. The change is primarily attributable to the difference in income (loss) before taxes between the periods and the reduced federal statutory rate from 2017 to 2018. In 2017, the income tax benefit was primarily due to the Tax Act and the resulting reduction of the federal corporate tax rate from 35% to 21%, which under GAAP results in a recalculation of the Company’s ending balance sheet deferred tax balances.

 

Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Company’s consolidated Carnero and Centrahoma joint ventures, Cedar Bayou Fractionators and Venice Energy Services Company, L.L.C.

 

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


 


 

The following table provides summary data regarding results of operations of this segment for the periods indicated:

 

 

Three Months Ended

December 31,

 

 

 

 

 

 

 

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018 vs. 2017

 

 

2018

 

 

2017

 

 

 

2018 vs. 2017

 

Gross margin

$

 

360.4

 

 

$

 

328.1

 

 

$

 

32.3

 

 

10

%

 

$

 

1,406.7

 

 

$

 

1,145.5

 

 

$

 

261.2

 

 

23

%

Operating expenses

 

 

110.4

 

 

 

 

93.7

 

 

 

 

16.7

 

 

18

%

 

 

 

438.3

 

 

 

 

361.7

 

 

 

 

76.6

 

 

21

%

Operating margin

$

 

250.0

 

 

$

 

234.4

 

 

$

 

15.6

 

 

7

%

 

$

 

968.4

 

 

$

 

783.8

 

 

$

 

184.6

 

 

24

%

Operating statistics (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

1,260.7

 

 

 

 

978.4

 

 

 

 

282.3

 

 

29

%

 

 

 

1,141.2

 

 

 

 

893.5

 

 

 

 

247.7

 

 

28

%

Permian Delaware (4)

 

 

477.8

 

 

 

 

406.1

 

 

 

 

71.7

 

 

18

%

 

 

 

443.9

 

 

 

 

381.8

 

 

 

 

62.1

 

 

16

%

Total Permian

 

 

1,738.5

 

 

 

 

1,384.5

 

 

 

 

354.0

 

 

 

 

 

 

 

1,585.1

 

 

 

 

1,275.3

 

 

 

 

309.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

365.4

 

 

 

 

365.6

 

 

 

 

(0.2

)

 

 

 

 

 

389.6

 

 

 

 

273.2

 

 

 

 

116.4

 

 

43

%

North Texas

 

 

247.4

 

 

 

 

251.5

 

 

 

 

(4.1

)

 

(2

%)

 

 

 

244.1

 

 

 

 

268.1

 

 

 

 

(24.0

)

 

(9

%)

SouthOK

 

 

574.1

 

 

 

 

540.1

 

 

 

 

34.0

 

 

6

%

 

 

 

555.7

 

 

 

 

494.0

 

 

 

 

61.7

 

 

12

%

WestOK

 

 

354.0

 

 

 

 

363.5

 

 

 

 

(9.5

)

 

(3

%)

 

 

 

351.6

 

 

 

 

377.7

 

 

 

 

(26.1

)

 

(7

%)

Total Central

 

 

1,540.9

 

 

 

 

1,520.7

 

 

 

 

20.2

 

 

 

 

 

 

 

1,541.0

 

 

 

 

1,413.0

 

 

 

 

128.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (5)

 

 

90.4

 

 

 

 

66.5

 

 

 

 

23.9

 

 

36

%

 

 

 

85.1

 

 

 

 

56.5

 

 

 

 

28.6

 

 

51

%

Total Field

 

 

3,369.8

 

 

 

 

2,971.7

 

 

 

 

398.1

 

 

 

 

 

 

 

3,211.2

 

 

 

 

2,744.8

 

 

 

 

466.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

731.1

 

 

 

 

665.7

 

 

 

 

65.4

 

 

10

%

 

 

 

726.2

 

 

 

 

728.8

 

 

 

 

(2.6

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

4,100.9

 

 

 

 

3,637.4

 

 

 

 

463.5

 

 

13

%

 

 

 

3,937.4

 

 

 

 

3,473.6

 

 

 

 

463.8

 

 

13

%

NGL production, MBbl/d (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Midland (4)

 

 

169.2

 

 

 

 

137.5

 

 

 

 

31.7

 

 

23

%

 

 

 

153.4

 

 

 

 

118.3

 

 

 

 

35.1

 

 

30

%

Permian Delaware (4)

 

 

58.9

 

 

 

 

45.2

 

 

 

 

13.7

 

 

30

%

 

 

 

53.5

 

 

 

 

43.1

 

 

 

 

10.4

 

 

24

%

Total Permian

 

 

228.1

 

 

 

 

182.7

 

 

 

 

45.4

 

 

 

 

 

 

 

206.9

 

 

 

 

161.4

 

 

 

 

45.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

47.0

 

 

 

 

45.7

 

 

 

 

1.3

 

 

3

%

 

 

 

51.1

 

 

 

 

30.4

 

 

 

 

20.7

 

 

68

%

North Texas

 

 

28.2

 

 

 

 

28.6

 

 

 

 

(0.4

)

 

(1

%)

 

 

 

28.1

 

 

 

 

30.2

 

 

 

 

(2.1

)

 

(7

%)

SouthOK

 

 

57.6

 

 

 

 

48.9

 

 

 

 

8.7

 

 

18

%

 

 

 

54.7

 

 

 

 

42.8

 

 

 

 

11.9

 

 

28

%

WestOK

 

 

22.4

 

 

 

 

20.5

 

 

 

 

1.9

 

 

9

%

 

 

 

20.5

 

 

 

 

21.9

 

 

 

 

(1.4

)

 

(6

%)

Total Central

 

 

155.2

 

 

 

 

143.7

 

 

 

 

11.5

 

 

 

 

 

 

 

154.4

 

 

 

 

125.3

 

 

 

 

29.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

11.8

 

 

 

 

9.4

 

 

 

 

2.4

 

 

26

%

 

 

 

10.8

 

 

 

 

7.9

 

 

 

 

2.9

 

 

37

%

Total Field

 

 

395.1

 

 

 

 

335.8

 

 

 

 

59.3

 

 

 

 

 

 

 

372.1

 

 

 

 

294.6

 

 

 

 

77.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

45.9

 

 

 

 

39.8

 

 

 

 

6.1

 

 

15

%

 

 

 

43.6

 

 

 

 

38.6

 

 

 

 

5.0

 

 

13

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

441.0

 

 

 

 

375.6

 

 

 

 

65.4

 

 

17

%

 

 

 

415.7

 

 

 

 

333.2

 

 

 

 

82.5

 

 

25

%

Crude oil gathered, Badlands, MBbl/d

 

 

167.3

 

 

 

 

119.8

 

 

 

 

47.5

 

 

40

%

 

 

 

146.8

 

 

 

 

113.6

 

 

 

 

33.2

 

 

29