HOUSTON, Aug. 03, 2017 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE:TRGP) (“TRC”, the “Company” or “Targa”)
today reported second quarter 2017 results.
Second Quarter 2017 Financial Results
Second quarter 2017 net income attributable to Targa Resources Corp. was $57.6 million compared to a net loss of
($23.2) million for the second quarter of 2016.
The Company reported earnings before interest, income taxes, depreciation and amortization, and other non-cash
items (“Adjusted EBITDA”) of $257.9 million for the second quarter of 2017 compared to $257.1 million for the second quarter
of 2016 (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”)).
“Our second quarter financial results were in-line with our expectations, and we are confident that our
financial performance will meet or exceed our full year 2017 financial expectations,” said Joe Bob Perkins, Chief Executive Officer
of the Company. “A pivotal development during the quarter was our announcement to move forward with a 300 thousand barrel per
day common carrier NGL Pipeline from the Permian Basin to Mont Belvieu (“Grand Prix”), which is expected to commence operation in
the second quarter of 2019. Grand Prix will connect our expansive and growing Permian Basin footprint to our downstream
assets at Mont Belvieu. Today, we have approximately 1.7 billion cubic feet per day of processing capacity in the Permian
Basin, with another 710 million cubic feet per day under construction that will come online by the third quarter of 2018. Our
strong long-term outlook beyond 2017 is supported by our visibility around activity levels and projects coming online, including
our Gathering and Processing projects, the addition of Grand Prix and other opportunities in our Downstream segment.”
On July 19, 2017, TRC declared a quarterly dividend of $0.91 per share of its common stock for the
three months ended June 30, 2017, or $3.64 per share on an annualized basis. Total cash dividends of approximately $196.2
million will be paid on August 15, 2017 on all outstanding shares of common stock to holders of record as of the close of business
on August 1, 2017. Also on July 19, 2017, 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 August 14, 2017 on all outstanding shares of
Series A Preferred Stock to holders of record as of the close of business on August 1, 2017.
The Company reported distributable cash flow for the second quarter of 2017 of $196.0 million compared to total
common dividends to be paid of $196.2 million and total Series A Preferred Stock dividends to be paid of $22.9 million.
Second Quarter 2017 - Capitalization, Liquidity and Financing
Targa’s total consolidated debt as of June 30, 2017 was $4,437.6 million including $435.0 million
outstanding under TRC’s $670.0 million senior secured revolving credit facility due 2020. The consolidated debt included $4,002.6
million of Targa Resource Partners LP (“TRP” or “the Partnership”) debt, net of $25.9 million of debt issuance costs, with no
amounts outstanding under TRP’s $1.6 billion senior secured revolving credit facility due 2020, $250.0 million outstanding under
TRP’s accounts receivable securitization facility and $3,778.5 million of outstanding TRP senior notes, net of unamortized
premiums. In June 2017, the Partnership redeemed its outstanding 6⅜% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling
$278.7 million in aggregate principal amount, at a price of 103.188% plus accrued interest through the redemption date.
As of June 30, 2017, TRC had available senior secured revolving credit facility capacity of $235.0 million. TRP
had no borrowings outstanding under its $1.6 billion senior secured revolving credit facility and $20.4 million in outstanding
letters of credit, resulting in available senior secured revolving credit facility capacity of $1,579.6 million at the Partnership.
Total Targa consolidated liquidity as of June 30, 2017, including $98.7 million of cash, was approximately $1.9 billion.
On June 1, 2017, TRC completed a public offering of 17,000,000 shares of its common stock at a price to the
public of $46.10, providing net proceeds after underwriting discounts, commissions and other expenses of $777.3 million. Targa used
the net proceeds from this public offering to fund a portion of the capital expenditures related to the construction of Grand Prix,
repay outstanding borrowings under its credit facilities, redeem the Partnership’s 6⅜% Senior Notes, and for general corporate
purposes.
2017 Forecasted Capital Expenditures Update
In May 2017, Targa announced plans to construct a new common carrier NGL pipeline, Grand Prix, which will
transport volumes from the Permian Basin, and also from its North Texas system, to its fractionation and storage complex in the NGL
market hub at Mont Belvieu. Grand Prix will be supported by Targa plant volumes and other third party customer commitments, and is
expected to be in service in the second quarter of 2019. The initial capacity of the pipeline from the Permian Basin will be
approximately 300 MBbl/d and will be expandable to 550 MBbl/d with the addition of pump stations. The total net growth capital
expenditures for Grand Prix are expected to be approximately $1.3 billion, with approximately $330 million of spending in 2017.
Including spending related to Grand Prix and additional growth capital to support increasing activity levels
around the Company’s assets, Targa now expects 2017 net growth capital expenditures for announced projects will be approximately
$1,375.0 million, an increase from the previously disclosed $1,210.0 million. Targa continues to expect that 2017 net
maintenance capital expenditures will be approximately $110.0 million.
Conference Call
The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m.
Central time) on August 3, 2017 to discuss second quarter 2017 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 http://ir.targaresources.com/trc/events.cfm or by dialing 877-881-2598. The
conference ID number for the dial-in is 56475709. Please dial in ten minutes prior to the scheduled start time. A replay will be
available approximately two hours following the completion of the webcast through the Investors section of the Company’s website.
Presentation slides will also be available in the Events and Presentations section of the Company’s website, or directly at
http://ir.targaresources.com/trc/events.cfm.
Targa Resources Corp. – Consolidated Financial Results of Operations
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Three Months Ended June 30,
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Six Months Ended June 30,
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2017 |
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2016 |
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2017 vs.
2016 |
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2017 |
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2016 |
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2017 vs.
2016 |
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(In millions, except operating statistics and
price amounts) |
Revenues |
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Sales of commodities |
$ |
1,623.8 |
|
|
$ |
1,312.9 |
|
|
$ |
310.9 |
|
|
24 |
% |
|
$ |
3,481.7 |
|
|
$ |
2,484.0 |
|
|
$ |
997.7 |
|
|
40 |
% |
Fees from midstream services |
|
243.9 |
|
|
|
270.7 |
|
|
|
(26.8 |
) |
|
(10 |
%) |
|
|
498.6 |
|
|
|
542.0 |
|
|
|
(43.4 |
) |
|
(8 |
%) |
Total revenues |
|
1,867.7 |
|
|
|
1,583.6 |
|
|
|
284.1 |
|
|
18 |
% |
|
|
3,980.3 |
|
|
|
3,026.0 |
|
|
|
954.3 |
|
|
32 |
% |
Product purchases |
|
1,420.6 |
|
|
|
1,145.2 |
|
|
|
275.4 |
|
|
24 |
% |
|
|
3,074.8 |
|
|
|
2,156.2 |
|
|
|
918.6 |
|
|
43 |
% |
Gross margin (1) |
|
447.1 |
|
|
|
438.4 |
|
|
|
8.7 |
|
|
2 |
% |
|
|
905.5 |
|
|
|
869.8 |
|
|
|
35.7 |
|
|
4 |
% |
Operating expenses |
|
155.2 |
|
|
|
138.9 |
|
|
|
16.3 |
|
|
12 |
% |
|
|
307.2 |
|
|
|
271.0 |
|
|
|
36.2 |
|
|
13 |
% |
Operating margin (1) |
|
291.9 |
|
|
|
299.5 |
|
|
|
(7.6 |
) |
|
(3 |
%) |
|
|
598.3 |
|
|
|
598.8 |
|
|
|
(0.5 |
) |
|
— |
|
Depreciation and amortization expense |
|
203.4 |
|
|
|
186.1 |
|
|
|
17.3 |
|
|
9 |
% |
|
|
394.6 |
|
|
|
379.6 |
|
|
|
15.0 |
|
|
4 |
% |
General and administrative expense |
|
51.0 |
|
|
|
47.0 |
|
|
|
4.0 |
|
|
9 |
% |
|
|
99.6 |
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|
|
92.2 |
|
|
|
7.4 |
|
|
8 |
% |
Goodwill impairment |
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— |
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|
|
— |
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|
— |
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— |
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— |
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|
|
24.0 |
|
|
|
(24.0 |
) |
|
(100 |
%) |
Other operating (income) expense |
|
0.3 |
|
|
|
0.1 |
|
|
|
0.2 |
|
|
200 |
% |
|
|
16.5 |
|
|
|
1.1 |
|
|
|
15.4 |
|
|
NM |
|
Income from operations |
|
37.2 |
|
|
|
66.3 |
|
|
|
(29.1 |
) |
|
(44 |
%) |
|
|
87.6 |
|
|
|
101.9 |
|
|
|
(14.3 |
) |
|
(14 |
%) |
Interest expense, net |
|
(62.1 |
) |
|
|
(71.4 |
) |
|
|
9.3 |
|
|
13 |
% |
|
|
(125.1 |
) |
|
|
(124.3 |
) |
|
|
(0.8 |
) |
|
1 |
% |
Equity earnings (loss) |
|
(4.2 |
) |
|
|
(4.4 |
) |
|
|
0.2 |
|
|
5 |
% |
|
|
(16.8 |
) |
|
|
(9.2 |
) |
|
|
(7.6 |
) |
|
83 |
% |
Gain (loss) from financing activities |
|
(10.7 |
) |
|
|
(3.3 |
) |
|
|
(7.4 |
) |
|
224 |
% |
|
|
(16.5 |
) |
|
|
21.4 |
|
|
|
(37.9 |
) |
|
(177 |
%) |
Other income (expense), net |
|
4.4 |
|
|
|
(0.1 |
) |
|
|
4.5 |
|
|
NM |
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|
|
(4.0 |
) |
|
|
(0.2 |
) |
|
|
(3.8 |
) |
|
NM |
|
Income tax (expense) benefit |
|
106.0 |
|
|
|
(1.7 |
) |
|
|
107.7 |
|
|
NM |
|
|
|
34.9 |
|
|
|
(4.8 |
) |
|
|
39.7 |
|
|
NM |
|
Net income (loss) |
|
70.6 |
|
|
|
(14.6 |
) |
|
|
85.2 |
|
|
NM |
|
|
|
(39.9 |
) |
|
|
(15.2 |
) |
|
|
(24.7 |
) |
|
163 |
% |
Less: Net income attributable to noncontrolling interests
|
|
13.0 |
|
|
|
8.6 |
|
|
|
4.4 |
|
|
51 |
% |
|
|
21.8 |
|
|
|
10.7 |
|
|
|
11.1 |
|
|
104 |
% |
Net income (loss) attributable to Targa Resources Corp. |
|
57.6 |
|
|
|
(23.2 |
) |
|
|
80.8 |
|
|
NM |
|
|
|
(61.7 |
) |
|
|
(25.9 |
) |
|
|
(35.8 |
) |
|
138 |
% |
Dividends on Series A preferred stock |
|
22.9 |
|
|
|
22.9 |
|
|
|
— |
|
|
— |
|
|
|
45.8 |
|
|
|
26.7 |
|
|
|
19.1 |
|
|
72 |
% |
Deemed dividends on Series A preferred stock |
|
6.3 |
|
|
|
6.5 |
|
|
|
(0.2 |
) |
|
(3 |
%) |
|
|
12.5 |
|
|
|
6.5 |
|
|
|
6.0 |
|
|
92 |
% |
Net income (loss) attributable to common shareholders |
$ |
28.4 |
|
|
$ |
(52.6 |
) |
|
$ |
81.0 |
|
|
154 |
% |
|
$ |
(120.0 |
) |
|
$ |
(59.1 |
) |
|
$ |
(60.9 |
) |
|
103 |
% |
Financial and operating data: |
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Financial data: |
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|
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|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
257.9 |
|
|
$ |
257.1 |
|
|
$ |
0.8 |
|
|
— |
|
|
$ |
534.6 |
|
|
$ |
521.8 |
|
|
$ |
12.8 |
|
|
2 |
% |
Distributable cash flow (1) |
|
196.0 |
|
|
|
169.6 |
|
|
|
26.4 |
|
|
16 |
% |
|
|
390.2 |
|
|
|
347.6 |
|
|
|
42.6 |
|
|
12 |
% |
Capital expenditures |
|
434.5 |
|
|
|
114.9 |
|
|
|
319.6 |
|
|
278 |
% |
|
|
609.1 |
|
|
|
291.8 |
|
|
|
317.3 |
|
|
109 |
% |
Business acquisition (2) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
— |
|
|
|
987.1 |
|
|
|
— |
|
|
|
987.1 |
|
|
— |
|
Operating statistics: (3) |
|
|
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|
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|
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|
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|
|
|
|
|
|
Crude oil gathered, Badlands, MBbl/d |
|
112.5 |
|
|
|
105.2 |
|
|
|
7.3 |
|
|
7 |
% |
|
|
113.0 |
|
|
|
106.6 |
|
|
|
6.4 |
|
|
6 |
% |
Crude oil gathered, Permian, MBbl/d (4) |
|
28.6 |
|
|
|
— |
|
|
|
28.6 |
|
|
— |
|
|
|
18.9 |
|
|
|
— |
|
|
|
18.9 |
|
|
— |
|
Plant natural gas inlet, MMcf/d (5) (6) |
|
3,391.2 |
|
|
|
3,511.4 |
|
|
|
(120.2 |
) |
|
(3 |
%) |
|
|
3,304.6 |
|
|
|
3,452.1 |
|
|
|
(147.5 |
) |
|
(4 |
%) |
Gross NGL production, MBbl/d |
|
321.2 |
|
|
|
321.0 |
|
|
|
0.2 |
|
|
— |
|
|
|
305.0 |
|
|
|
302.8 |
|
|
|
2.2 |
|
|
1 |
% |
Export volumes, MBbl/d (7) |
|
155.3 |
|
|
|
181.3 |
|
|
|
(26.0 |
) |
|
(14 |
%) |
|
|
186.2 |
|
|
|
181.2 |
|
|
|
5.0 |
|
|
3 |
% |
Natural gas sales, BBtu/d (6) (8) |
|
1,957.3 |
|
|
|
1,958.4 |
|
|
|
(1.1 |
) |
|
— |
|
|
|
1,885.7 |
|
|
|
1,966.5 |
|
|
|
(80.8 |
) |
|
(4 |
%) |
NGL sales, MBbl/d (8) |
|
473.9 |
|
|
|
516.8 |
|
|
|
(42.9 |
) |
|
(8 |
%) |
|
|
503.6 |
|
|
|
532.3 |
|
|
|
(28.7 |
) |
|
(5 |
%) |
Condensate sales, MBbl/d |
|
12.1 |
|
|
|
11.4 |
|
|
|
0.7 |
|
|
6 |
% |
|
|
11.5 |
|
|
|
10.4 |
|
|
|
1.1 |
|
|
11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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) |
|
Includes the preliminary acquisition date fair value of the potential
earn-out payments of $416.3 million due in 2018 and 2019. |
(3) |
|
These volume statistics are presented with the numerator as the total
volume sold during the quarter and the denominator as the number of calendar days during the quarter. |
(4) |
|
Includes operations from the Permian Acquisition for the period
effective March 1, 2017. For the volume statistics presented, the numerator is the total volume sold during the period of our
ownership while the denominator is the number of calendar days during the quarter. |
(5) |
|
Plant natural gas inlet represents the volume of natural gas passing
through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total
wellhead gathered volume. |
(6) |
|
Plant natural gas inlet volumes include producer take-in-kind volumes,
while natural gas sales exclude producer take-in-kind volumes. |
(7) |
|
Export volumes represent the quantity of NGL products delivered to
third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets. |
(8) |
|
Includes the impact of intersegment eliminations. |
NM |
|
Due to a low denominator, the noted percentage change is
disproportionately high and as a result, considered not meaningful. |
Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016
The increase in commodity sales was primarily due to higher commodity prices ($386.8 million) and higher petroleum products and
condensate volumes ($13.7 million), partially offset by decreased NGL sales volumes ($77.0 million) and the impact of hedge
settlements ($12.6 million). Fee-based and other revenues decreased primarily due to lower export fees and volumes, partially
offset by higher crude gathering and gas processing fees.
The increase in product purchases was primarily due to the impact of higher commodity prices, partially offset
by decreased volumes.
The higher gross margin in 2017 reflects increased segment margin results for Gathering and Processing,
partially offset by decreased Logistics and Marketing segment margins. Operating margin decreased as the increases in operating
expenses more than offset the increases in gross margin. Operating expenses increased compared to 2016 due to higher fuel and power
and higher maintenance in the Logistics and Marketing segment and the impact of the Permian Acquisition and other plant and system
expansions in 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.
The increase in depreciation and amortization expense reflects the impact of the Permian Acquisition and other
growth investments, partially offset by the impact of fully depreciated property assets and lower scheduled amortization on the
Badlands intangibles.
General and administrative expense increased primarily due to higher compensation and benefits, partially offset
by lower professional services.
Net interest expense decreased primarily due to the impact of lower average outstanding borrowings during
2017.
During 2017, the Company recorded a loss from financing activities of $10.7 million on the redemption of the
outstanding 6⅜% Senior Notes, whereas in 2016 the Company recorded a loss of $3.3 million on open market debt repurchases.
The income tax benefit for the three months ended June 30, 2017 is the result of the difference between the
annual effective tax rate used to calculate income tax (expense) benefit for the three months ended March 31, 2017 and the
statutory rate used to calculate income tax (expense) benefit for the six months ended June 30, 2017. For additional discussion of
the basis for the calculation of the income tax benefit for the six months ended June 30, 2017, see the income tax explanation
under the Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016.
Net income attributable to noncontrolling interests was higher in 2017 due to increased earnings at our joint
ventures as compared with 2016.
Preferred dividends represent both cash dividends related to the March 2016 Series A Preferred Stock offering
and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature.
Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
The increase in commodity sales was primarily due to higher commodity prices ($1,148.6 million) and higher
petroleum products and condensate volumes ($18.3 million), partially offset by decreased NGL and natural gas sales volumes ($131.1
million) and the impact of hedge settlements ($38.1 million). Fee-based and other revenues decreased primarily due to lower export
fees.
The increase in product purchases was primarily due to the impact of higher commodity prices, partially offset
by decreased volumes.
The higher gross margin in 2017 reflects increased segment margin results for Gathering and Processing,
partially offset by decreased Logistics and Marketing segment margins. Operating margin was relatively flat as compared to 2016 as
the increases in gross margin were offset by the increases in operating expenses. Operating expenses increased compared to 2016 due
to higher maintenance, higher fuel and power, and higher labor in the Logistics and Marketing segment and plant and system
expansions. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin
on a segment basis.
The increase in depreciation and amortization expense reflects four months of operations from the Permian
Acquisition in 2017 and the impact of other growth investments, primarily CBF Train 5 which went into service in the second quarter
of 2016, partially offset by the impact of fully depreciated property assets and lower scheduled amortization on the Badlands
intangibles.
General and administrative expense increased primarily due to higher compensation and benefits, partially offset
by lower professional services.
The Company recognized an impairment of goodwill in the first quarter of 2016 of $24.0 million to finalize the
2015 provisional impairment of goodwill. The impairment charge related to goodwill acquired in the mergers with Atlas Energy L.P.
and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”).
Other operating (income) expense in 2017 includes the loss due to the reduction in the carrying value of the
Company’s ownership interest in the Venice Gathering System in connection with the April 4, 2017 sale.
Net interest expense in 2017 was flat as compared with 2016. Higher non-cash interest expense related to the
mandatorily redeemable preferred interests liability that is revalued quarterly at the estimated redemption value as of the
reporting date was offset by lower average outstanding borrowings during 2017.
Higher equity losses in 2017 reflects a $12.0 million loss provision due to the impairment of the Company’s
investment in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.
During 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, whereas in
2016 the Company recorded a gain of $21.4 million on open market debt repurchases.
The Company has historically calculated the provision for income taxes during interim reporting periods by
applying an estimate of the annual effective tax rate for the full fiscal year to ordinary income or loss (pretax income or loss
excluding unusual or infrequently occurring discrete items) for the reporting period. When calculating the annual estimated
effective income tax rate for the six months ended June 30, 2017, the Company was subject to a loss limitation rule because the
year-to-date ordinary loss exceeded the full-year expected ordinary loss. The tax benefit for that year-to-date ordinary loss was
limited to the amount that would be recognized if the year-to-date ordinary loss were the anticipated ordinary loss for the full
year. This requires the Company to use its statutory rate of 37.3% rather than the annual estimated effective tax rate to
calculate the benefit for the period.
Net income attributable to noncontrolling interests was higher in 2017 due to the February 2016 TRC/TRP Merger,
which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for a portion of the first
quarter 2016, and the Company’s October 2016 acquisition of the 37% interest of Versado that they did not already own. Further,
earnings at the Company’s joint ventures increased as compared with 2016.
Preferred dividends represent both cash dividends related to the March 2016 Series A Preferred Stock offering
and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. Preferred
dividends increased as the Series A Preferred Stock was outstanding for two full quarters in 2017, as compared to a portion of
2016.
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 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; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore,
and Arkoma Basins in Oklahoma 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.
The following table provides summary data regarding results of operations of this segment for the periods
indicated:
|
|
Three Months Ended
June 30, |
|
|
|
|
|
|
Six Months Ended June
30, |
|
|
|
|
|
|
|
2017 |
|
2016 |
|
2017 vs.
2016 |
|
2017 |
|
2016 |
|
|
2017 vs.
2016 |
Gross margin |
|
$ |
264.2 |
|
$ |
222.4 |
|
$ |
41.8 |
|
|
19 |
% |
|
$ |
527.4 |
|
$ |
416.5 |
|
$ |
110.9 |
|
|
27 |
% |
Operating expenses |
|
|
90.7 |
|
|
83.3 |
|
|
7.4 |
|
|
9 |
% |
|
|
176.3 |
|
|
161.8 |
|
|
14.5 |
|
|
9 |
% |
Operating margin |
|
$ |
173.5 |
|
$ |
139.1 |
|
$ |
34.4 |
|
|
25 |
% |
|
$ |
351.1 |
|
$ |
254.7 |
|
$ |
96.4 |
|
|
38 |
% |
Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
|
311.6 |
|
|
259.2 |
|
|
52.4 |
|
|
20 |
% |
|
|
293.7 |
|
|
251.3 |
|
|
42.4 |
|
|
17 |
% |
WestTX |
|
|
541.6 |
|
|
481.4 |
|
|
60.2 |
|
|
13 |
% |
|
|
526.5 |
|
|
464.7 |
|
|
61.8 |
|
|
13 |
% |
Total Permian Midland |
|
|
853.2 |
|
|
740.6 |
|
|
112.6 |
|
|
|
|
|
820.2 |
|
|
716.0 |
|
|
104.2 |
|
|
|
Sand Hills (4) |
|
|
181.7 |
|
|
135.8 |
|
|
45.9 |
|
|
34 |
% |
|
|
160.7 |
|
|
143.4 |
|
|
17.3 |
|
|
12 |
% |
Versado |
|
|
196.5 |
|
|
168.8 |
|
|
27.7 |
|
|
16 |
% |
|
|
197.5 |
|
|
174.4 |
|
|
23.1 |
|
|
13 |
% |
Total Permian Delaware |
|
|
378.2 |
|
|
304.6 |
|
|
73.6 |
|
|
|
|
|
358.2 |
|
|
317.8 |
|
|
40.4 |
|
|
|
Total Permian |
|
|
1,231.4 |
|
|
1,045.2 |
|
|
186.2 |
|
|
|
|
|
1,178.4 |
|
|
1,033.8 |
|
|
144.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
222.6 |
|
|
265.4 |
|
|
(42.8 |
) |
|
(16 |
%) |
|
|
197.4 |
|
|
220.5 |
|
|
(23.1 |
) |
|
(10 |
%) |
North Texas |
|
|
277.1 |
|
|
327.5 |
|
|
(50.4 |
) |
|
(15 |
%) |
|
|
279.8 |
|
|
327.5 |
|
|
(47.7 |
) |
|
(15 |
%) |
SouthOK |
|
|
479.0 |
|
|
470.7 |
|
|
8.3 |
|
|
2 |
% |
|
|
459.8 |
|
|
464.3 |
|
|
(4.5 |
) |
|
(1 |
%) |
WestOK |
|
|
387.4 |
|
|
445.6 |
|
|
(58.2 |
) |
|
(13 |
%) |
|
|
390.3 |
|
|
466.3 |
|
|
(76.0 |
) |
|
(16 |
%) |
Total Central |
|
|
1,366.1 |
|
|
1,509.2 |
|
|
(143.1 |
) |
|
|
|
|
1,327.3 |
|
|
1,478.6 |
|
|
(151.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) |
|
|
52.2 |
|
|
51.2 |
|
|
1.0 |
|
|
2 |
% |
|
|
49.1 |
|
|
52.5 |
|
|
(3.4 |
) |
|
(6 |
%) |
Total Field |
|
|
2,649.7 |
|
|
2,605.6 |
|
|
44.1 |
|
|
|
|
|
2,554.8 |
|
|
2,564.9 |
|
|
(10.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
741.6 |
|
|
905.8 |
|
|
(164.2 |
) |
|
(18 |
%) |
|
|
749.9 |
|
|
887.2 |
|
|
(137.3 |
) |
|
(15 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,391.3 |
|
|
3,511.4 |
|
|
(120.1 |
) |
|
(3 |
%) |
|
|
3,304.7 |
|
|
3,452.1 |
|
|
(147.4 |
) |
|
(4 |
%) |
Gross NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
|
37.9 |
|
|
32.2 |
|
|
5.7 |
|
|
18 |
% |
|
|
35.6 |
|
|
30.7 |
|
|
4.9 |
|
|
16 |
% |
WestTX |
|
|
74.9 |
|
|
61.9 |
|
|
13.0 |
|
|
21 |
% |
|
|
70.7 |
|
|
57.2 |
|
|
13.5 |
|
|
24 |
% |
Total Permian Midland |
|
|
112.8 |
|
|
94.1 |
|
|
18.7 |
|
|
|
|
|
106.3 |
|
|
87.9 |
|
|
18.4 |
|
|
|
Sand Hills (4) |
|
|
20.0 |
|
|
14.1 |
|
|
5.9 |
|
|
42 |
% |
|
|
17.4 |
|
|
14.9 |
|
|
2.5 |
|
|
17 |
% |
Versado |
|
|
22.9 |
|
|
20.2 |
|
|
2.7 |
|
|
13 |
% |
|
|
23.0 |
|
|
21.1 |
|
|
1.9 |
|
|
9 |
% |
Total Permian Delaware |
|
|
42.9 |
|
|
34.3 |
|
|
8.6 |
|
|
|
|
|
40.4 |
|
|
36.0 |
|
|
4.4 |
|
|
|
Total Permian |
|
|
155.7 |
|
|
128.4 |
|
|
27.3 |
|
|
|
|
|
146.7 |
|
|
123.9 |
|
|
22.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
23.5 |
|
|
31.4 |
|
|
(7.9 |
) |
|
(25 |
%) |
|
|
20.1 |
|
|
27.3 |
|
|
(7.2 |
) |
|
(26 |
%) |
North Texas |
|
|
31.1 |
|
|
37.0 |
|
|
(5.9 |
) |
|
(16 |
%) |
|
|
31.5 |
|
|
36.3 |
|
|
(4.8 |
) |
|
(13 |
%) |
SouthOK |
|
|
38.5 |
|
|
47.3 |
|
|
(8.8 |
) |
|
(19 |
%) |
|
|
39.7 |
|
|
37.6 |
|
|
2.1 |
|
|
6 |
% |
WestOK |
|
|
23.5 |
|
|
29.7 |
|
|
(6.2 |
) |
|
(21 |
%) |
|
|
23.1 |
|
|
28.3 |
|
|
(5.2 |
) |
|
(18 |
%) |
Total Central |
|
|
116.6 |
|
|
145.4 |
|
|
(28.8 |
) |
|
|
|
|
114.4 |
|
|
129.5 |
|
|
(15.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
|
7.7 |
|
|
7.0 |
|
|
0.7 |
|
|
10 |
% |
|
|
6.6 |
|
|
7.3 |
|
|
(0.7 |
) |
|
(10 |
%) |
Total Field |
|
|
280.0 |
|
|
280.8 |
|
|
(0.8 |
) |
|
|
|
|
267.7 |
|
|
260.7 |
|
|
7.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
41.2 |
|
|
40.1 |
|
|
1.1 |
|
|
3 |
% |
|
|
37.3 |
|
|
42.2 |
|
|
(4.9 |
) |
|
(12 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
321.2 |
|
|
320.9 |
|
|
0.3 |
|
|
— |
|
|
|
305.0 |
|
|
302.9 |
|
|
2.1 |
|
|
1 |
% |
Crude oil gathered, Badlands, MBbl/d |
|
|
112.5 |
|
|
105.2 |
|
|
7.3 |
|
|
7 |
% |
|
|
113.0 |
|
|
106.6 |
|
|
6.4 |
|
|
6 |
% |
Crude oil gathered, Permian, MBbl/d (4) |
|
|
28.6 |
|
|
— |
|
|
28.6 |
|
|
— |
|
|
|
18.9 |
|
|
— |
|
|
18.9 |
|
|
— |
|
Natural gas sales, BBtu/d (3) |
|
|
1,655.2 |
|
|
1,605.8 |
|
|
49.6 |
|
|
3 |
% |
|
|
1,601.6 |
|
|
1,646.5 |
|
|
(44.9 |
) |
|
(3 |
%) |
NGL sales, MBbl/d |
|
|
249.2 |
|
|
256.1 |
|
|
(6.9 |
) |
|
(3 |
%) |
|
|
238.4 |
|
|
237.7 |
|
|
0.7 |
|
|
— |
|
Condensate sales, MBbl/d |
|
|
12.1 |
|
|
10.9 |
|
|
1.3 |
|
|
12 |
% |
|
|
11.4 |
|
|
10.2 |
|
|
1.3 |
|
|
13 |
% |
Average realized prices (6): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
2.70 |
|
|
1.64 |
|
|
1.06 |
|
|
65 |
% |
|
|
2.79 |
|
|
1.70 |
|
|
1.09 |
|
|
64 |
% |
NGL, $/gal |
|
|
0.46 |
|
|
0.36 |
|
|
0.10 |
|
|
28 |
% |
|
|
0.48 |
|
|
0.32 |
|
|
0.16 |
|
|
50 |
% |
Condensate, $/Bbl |
|
|
42.74 |
|
|
37.94 |
|
|
4.81 |
|
|
13 |
% |
|
|
43.79 |
|
|
32.21 |
|
|
11.58 |
|
|
36 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Segment operating statistics include the effect of intersegment
amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is
the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
(2) |
|
Plant natural gas inlet represents the Company’s undivided interest
in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than the
Badlands. |
(3) |
|
Plant natural gas inlet volumes and gross NGL production volumes
include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes. |
(4) |
|
Includes operations from the Permian Acquisition for the period
effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes are included within Sand Hills.
For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while the
denominator is the number of calendar days during the quarter. |
(5) |
|
Badlands natural gas inlet represents the total wellhead gathered
volume. |
(6) |
|
Average realized prices exclude the impact of hedging activities
presented in Other. |
Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016
The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes, including
those associated with the Permian Acquisition in 2017. Inlet volumes for Field Gathering and Processing were higher primarily due
to increases at WestTX, SAOU, Sand Hills and Versado, partially offset by decreases at the other areas. The inlet volume decrease
for Coastal Gathering and Processing, which generates significantly lower margins, more than offset the Field Gathering and
Processing inlet volume increase. Higher NGL production in the Permian region was more than offset by lower NGL production in the
other areas. Natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. Total crude oil
gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered volumes and
natural gas volumes increased primarily due to system expansions.
The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and
system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.
Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes, including
those associated with the Permian Acquisition in 2017. Field Gathering and Processing inlet volume increases in the Permian region,
specifically at WestTX, SAOU, Versado and Sand Hills, were offset by decreases at the other areas. The inlet volume decrease for
Coastal Gathering and Processing, which generates significantly lower margins than does Field Gathering and Processing, accounted
for over 93% of the overall inlet volume decrease. Despite overall lower inlet volumes, NGL production and NGL sales increased
slightly primarily due to increased plant recoveries including additional ethane recovery. Natural gas sales decreased due to lower
inlet volumes and increased ethane recovery. Total crude oil gathered volumes increased in the Permian region due to the Permian
Acquisition. Total crude oil gathered in the Badlands increased due to system expansions. Badlands natural gas volumes decreased
primarily due to the impact of the severe winter weather in the first quarter of 2017.
The increase in operating expenses was primarily driven by plant and system expansions in the Permian region,
the inclusion of the Permian Acquisition and the June 2017 commencement in operations of the Raptor Plant at SouthTX.
Gross Operating Statistics Compared to Actual Reported
The table below provides a reconciliation between gross operating statistics and the actual reported operating
statistics for the Field portion of the Gathering and Processing segment:
|
|
|
Three Months Ended
June 30, 2017 |
Operating statistics: |
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
|
|
Gross Volume (3) |
|
Ownership
% |
|
Net Volume (3) |
|
Actual Reported |
SAOU (4) |
|
|
311.6 |
|
100 |
% |
|
311.6 |
|
311.6 |
WestTX (5) (6) |
|
|
743.9 |
|
73 |
% |
|
541.6 |
|
541.6 |
Total Permian Midland |
|
|
1,055.5 |
|
|
|
853.2 |
|
853.2 |
Sand Hills (4) |
|
|
181.7 |
|
100 |
% |
|
181.7 |
|
181.7 |
Versado (7) |
|
|
196.5 |
|
100 |
% |
|
196.5 |
|
196.5 |
Total Permian Delaware |
|
|
378.2 |
|
|
|
378.2 |
|
378.2 |
Total Permian |
|
|
1,433.7 |
|
|
|
1,231.4 |
|
1,231.4 |
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
222.6 |
|
Varies (8) (9) |
|
|
199.1 |
|
222.6 |
North Texas |
|
|
277.1 |
|
100 |
% |
|
277.1 |
|
277.1 |
SouthOK |
|
|
479.0 |
|
Varies (10) |
|
|
382.6 |
|
479.0 |
WestOK |
|
|
387.4 |
|
100 |
% |
|
387.4 |
|
387.4 |
Total Central |
|
|
1,366.1 |
|
|
|
1,246.2 |
|
1,366.1 |
|
|
|
|
|
|
|
|
|
|
Badlands (11) |
|
|
52.2 |
|
100 |
% |
|
52.2 |
|
52.2 |
Total Field |
|
|
2,852.0 |
|
|
|
2,529.8 |
|
2,649.7 |
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
|
37.9 |
|
100 |
% |
|
37.9 |
|
37.9 |
WestTX (5) (6) |
|
|
102.9 |
|
73 |
% |
|
74.9 |
|
74.9 |
Total Permian Midland |
|
|
140.8 |
|
|
|
112.8 |
|
112.8 |
Sand Hills (4) |
|
|
20.0 |
|
100 |
% |
|
20.0 |
|
20.0 |
Versado (7) |
|
|
22.9 |
|
100 |
% |
|
22.9 |
|
22.9 |
Total Permian Delaware |
|
|
42.9 |
|
|
|
42.9 |
|
42.9 |
Total Permian |
|
|
183.7 |
|
|
|
155.7 |
|
155.7 |
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
23.5 |
|
Varies (8) (9) |
|
|
20.8 |
|
23.5 |
North Texas |
|
|
31.1 |
|
100 |
% |
|
31.1 |
|
31.1 |
SouthOK |
|
|
38.5 |
|
Varies (10) |
|
|
31.4 |
|
38.5 |
WestOK |
|
|
23.5 |
|
100 |
% |
|
23.5 |
|
23.5 |
Total Central |
|
|
116.6 |
|
|
|
106.8 |
|
116.6 |
|
|
|
|
|
|
|
|
|
|
Badlands |
|
|
7.7 |
|
100 |
% |
|
7.7 |
|
7.7 |
Total Field |
|
|
308.0 |
|
|
|
270.2 |
|
280.0 |
|
|
(1) |
|
Plant natural gas inlet represents the volume of natural gas passing
through the meter located at the inlet of a natural gas processing plant. |
(2) |
|
Plant natural gas inlet volumes and gross NGL production volumes
include producer take-in-kind volumes. |
(3) |
|
For these volume statistics presented, the numerator is the total
volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
(4) |
|
Includes operations from the Permian Acquisition for the period
effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes
are included within Sand Hills. |
(5) |
|
Operating results for the WestTX undivided interest assets are
presented on a pro-rata net basis in the Company’s reported financials. |
(6) |
|
Includes the Buffalo Plant that commenced commercial operations in
April 2016. |
(7) |
|
Versado is a consolidated subsidiary and its financial results are
presented on a gross basis in the Company’s reported financials. The Company held a 63% interest in
Versado until October 31, 2016, when the Company acquired the remaining 37% interest. |
(8) |
|
SouthTX includes the Silver Oak II Plant, of which Targa owned a 90%
interest from October 2015 through May 2017, and after which Targa owns a 100% interest. Silver
Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported
financials. |
(9) |
|
SouthTX also includes the Raptor Plant, which began operations in
the second quarter of 2017, of which the Company owns a 50% interest through the Carnero Processing
Joint Venture. The Carnero Processing Joint Venture is a consolidated subsidiary and its financial results are presented on a
gross basis in the Company’s reported
financials. |
(10) |
|
SouthOK includes the Centrahoma Joint Venture, of which Targa owns
60%, and other plants which are owned 100% by Targa. Centrahoma is a consolidated subsidiary
and its financial results are presented on a gross basis in the Company’s reported financials. |
(11) |
|
Badlands natural gas inlet represents the total wellhead gathered
volume. |
|
|
|
Three Months Ended
June 30, 2016 |
Operating statistics: |
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
|
|
Gross Volume (3) |
|
Ownership
% |
|
Net Volume (3) |
|
Actual Reported |
SAOU |
|
|
259.2 |
|
100 |
% |
|
259.2 |
|
259.2 |
WestTX (4) |
|
|
661.2 |
|
73 |
% |
|
481.4 |
|
481.4 |
Total Permian Midland |
|
|
920.4 |
|
|
|
740.6 |
|
740.6 |
Sand Hills |
|
|
135.8 |
|
100 |
% |
|
135.8 |
|
135.8 |
Versado (5) |
|
|
168.8 |
|
63 |
% |
|
106.3 |
|
168.8 |
Total Permian Delaware |
|
|
304.6 |
|
|
|
242.1 |
|
304.6 |
Total Permian |
|
|
1,225.0 |
|
|
|
982.7 |
|
1,045.2 |
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
265.4 |
|
Varies (6) |
|
|
251.9 |
|
265.4 |
North Texas |
|
|
327.5 |
|
100 |
% |
|
327.5 |
|
327.5 |
SouthOK |
|
|
470.7 |
|
Varies (7) |
|
|
393.7 |
|
470.7 |
WestOK |
|
|
445.6 |
|
100 |
% |
|
445.6 |
|
445.6 |
Total Central |
|
|
1,509.2 |
|
|
|
1,418.7 |
|
1,509.2 |
|
|
|
|
|
|
|
|
|
|
Badlands (8) |
|
|
51.2 |
|
100 |
% |
|
51.2 |
|
51.2 |
Total Field |
|
|
2,785.4 |
|
|
|
2,452.6 |
|
2,605.6 |
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
SAOU |
|
|
32.2 |
|
100 |
% |
|
32.2 |
|
32.2 |
WestTX (4) |
|
|
85.0 |
|
73 |
% |
|
61.9 |
|
61.9 |
Total Permian Midland |
|
|
117.2 |
|
|
|
94.1 |
|
94.1 |
Sand Hills |
|
|
14.1 |
|
100 |
% |
|
14.1 |
|
14.1 |
Versado (5) |
|
|
20.2 |
|
63 |
% |
|
12.7 |
|
20.2 |
Total Permian Delaware |
|
|
34.3 |
|
|
|
26.8 |
|
34.3 |
Total Permian |
|
|
151.5 |
|
|
|
120.9 |
|
128.4 |
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
|
31.4 |
|
Varies (6) |
|
|
30.2 |
|
31.4 |
North Texas |
|
|
37.0 |
|
100 |
% |
|
37.0 |
|
37.0 |
SouthOK |
|
|
47.3 |
|
Varies (7) |
|
|
44.0 |
|
47.3 |
WestOK |
|
|
29.7 |
|
100 |
% |
|
29.7 |
|
29.7 |
Total Central |
|
|
145.4 |
|
|
|
140.9 |
|
145.4 |
|
|
|
|
|
|
|
|
|
|
Badlands |
|
|
7.0 |
|
100 |
% |
|
7.0 |
|
7.0 |
Total Field |
|
|
303.9 |
|
|
|
268.8 |
|
280.8 |
|
|
(1) |
|
Plant natural gas inlet represents the volume of natural gas passing
through the meter located at the inlet of a natural gas processing plant. |
(2) |
|
Plant natural gas inlet volumes and gross NGL production volumes
include producer take-in-kind volumes. |
(3) |
|
For these volume statistics presented, the numerator is the total
volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
(4) |
|
Operating results for the WestTX undivided interest assets are
presented on a pro-rata net basis in the Company’s reported financials. |
(5) |
|
Versado is a consolidated subsidiary and its financial results are
presented on a gross basis in the Company’s reported financials. The Company held a 63% interest in
Versado until October 31, 2016, when the Company acquired the remaining 37% interest. |
(6) |
|
SouthTX includes the Silver Oak II Plant, of which Targa owned a 90%
interest from October 2015 through May 2017, and after which Targa owns a 100% interest. Silver
Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported
financials. |
(7) |
|
SouthOK includes the Centrahoma Joint Venture, of which Targa owns
60%, and other plants which are owned 100% by Targa. Centrahoma is a consolidated subsidiary
and its financial results are presented on a gross basis in the Company’s reported financials. |
(8) |
|
Badlands natural gas inlet represents the total wellhead gathered
volume. |
Logistics and Marketing Segment
The Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL
products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage
and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of
Targa’s other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities
in support of the Company’s other operations, as well as transporting natural gas and NGLs.
Logistics and Marketing operations are generally connected to and supplied in part by the Company’s Gathering
and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma,
Washington.
The following table provides summary data regarding results of operations of this segment for the periods
indicated:
|
|
Three Months Ended
June 30, |
|
|
|
|
Six Months Ended
June 30, |
|
|
|
|
|
|
|
2017 |
|
2016 |
|
2017 vs.
2016 |
|
2017 |
|
2016 |
|
2017 vs.
2016 |
|
(In millions) |
Gross margin |
|
$ |
176.9 |
|
$ |
197.6 |
|
$ |
(20.7 |
) |
|
(10 |
%) |
|
$ |
373.2 |
|
$ |
407.9 |
|
$ |
(34.7 |
) |
|
(9 |
%) |
Operating expenses |
|
|
64.5 |
|
|
55.8 |
|
|
8.7 |
|
|
16 |
% |
|
|
130.8 |
|
|
109.4 |
|
|
21.4 |
|
|
20 |
% |
Operating margin |
|
$ |
112.4 |
|
$ |
141.8 |
|
$ |
(29.4 |
) |
|
(21 |
%) |
|
$ |
242.4 |
|
$ |
298.5 |
|
$ |
(56.1 |
) |
|
(19 |
%) |
Operating statistics MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (2)(3) |
|
|
338.5 |
|
|
329.8 |
|
|
8.7 |
|
|
3 |
% |
|
|
321.8 |
|
|
312.7 |
|
|
9.1 |
|
|
3 |
% |
LSNG treating volumes (2) |
|
|
33.3 |
|
|
23.1 |
|
|
10.2 |
|
|
44 |
% |
|
|
33.9 |
|
|
22.0 |
|
|
11.9 |
|
|
54 |
% |
Benzene treating volumes (2) |
|
|
22.1 |
|
|
23.1 |
|
|
(1.0 |
) |
|
(4 |
%) |
|
|
22.8 |
|
|
22.0 |
|
|
0.8 |
|
|
4 |
% |
Export volumes, MBbl/d (4) |
|
|
155.3 |
|
|
181.3 |
|
|
(26.0 |
) |
|
(14 |
%) |
|
|
186.2 |
|
|
181.2 |
|
|
5.0 |
|
|
3 |
% |
NGL sales, MBbl/d |
|
|
439.4 |
|
|
463.6 |
|
|
(24.2 |
) |
|
(5 |
%) |
|
|
470.5 |
|
|
472.8 |
|
|
(2.3 |
) |
|
— |
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL realized price, $/gal |
|
$ |
0.58 |
|
$ |
0.48 |
|
$ |
0.10 |
|
|
21 |
% |
|
$ |
0.62 |
|
$ |
0.44 |
|
$ |
0.18 |
|
|
41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Segment operating statistics include intersegment amounts, which have been
eliminated from the consolidated presentation. For all volume statistics presented,
the numerator is the total volume sold during the period and the denominator is the number of calendar days during the
period. |
(2) |
|
Fractionation and treating contracts include pricing terms composed of base fees
and fuel and power components which vary with the cost of energy. As such,
the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and
operating expenses. |
(3) |
|
Fractionation volumes reflect those volumes delivered and settled under
fractionation contracts. |
(4) |
|
Export volumes represent the quantity of NGL products delivered to third-party
customers at Targa’s Galena Park Marine Terminal that are destined for
international markets. |
Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016
Logistics and Marketing gross margin decreased due to lower LPG export margin partially offset by higher fractionation margin,
higher terminaling and storage throughput, and higher treating margin. LPG export margin decreased due to lower fees and volumes.
Fractionation margin increased due to higher fees, an increase in system product gains and higher supply volume. Fractionation
margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see
footnote (2) above). Treating margin increased slightly due to higher volumes partially offset by lower fees.
Operating expenses increased primarily due to higher fuel and power, which are largely passed through, and
higher labor primarily associated with Train 5.
Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
The six month gross margin results were impacted by the same factors as discussed above for the quarter except
that LPG export volumes were higher.
Operating expenses increased primarily due to higher fuel and power, which are largely passed through, higher
maintenance associated with unusual one-time events in the first quarter of 2017, and higher labor associated with Train 5.
Other
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended June
30, |
|
|
|
|
|
2017 |
|
|
2016 |
|
2017 vs.
2016 |
|
|
2017 |
|
|
2016 |
|
2017 vs.
2016 |
|
|
(In millions) |
Gross margin |
|
$ |
6.0 |
|
$ |
18.6 |
|
$ |
(12.6 |
) |
|
$ |
4.9 |
|
$ |
45.7 |
|
$ |
(40.8 |
) |
Operating margin |
|
$ |
6.0 |
|
$ |
18.6 |
|
$ |
(12.6 |
) |
|
$ |
4.9 |
|
$ |
45.7 |
|
$ |
(40.8 |
) |
Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to
Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gain/losses related to
derivative contracts that were not designated as cash flow hedges. The primary purpose of the Company’s commodity risk management
activities is to mitigate a portion of the impact of commodity prices on the Company’s operating cash flow. The Company has entered
into derivative instruments to hedge the commodity price associated with a portion of the Company’s expected natural gas, NGL and
condensate equity volumes in the Company’s Gathering and Processing Operations that result from percent of proceeds/liquids
processing arrangements. Because the Company is essentially forward-selling a portion of its future plant equity volumes, these
hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity
prices.
The following table provides a breakdown of the change in Other operating margin:
|
|
|
Three Months Ended
June 30, 2017 |
|
Three Months Ended
June 30, 2016 |
|
|
|
|
|
(In millions, except volumetric data and
price amounts) |
|
|
|
|
|
Volume
Settled |
|
Price
Spread
(1) |
|
Gain
(Loss) |
|
Volume
Settled |
|
Price
Spread
(1) |
|
Gain
(Loss) |
|
2017 vs.
2016 |
Natural gas (BBtu) |
|
|
15.5 |
|
$ |
0.16 |
|
|
$ |
2.5 |
|
|
10.7 |
|
$ |
1.27 |
|
$ |
13.6 |
|
|
$ |
(11.1 |
) |
NGL (MMgal) |
|
|
59.4 |
|
|
0.01 |
|
|
|
0.8 |
|
|
13.1 |
|
|
0.09 |
|
|
1.0 |
|
|
|
(0.2 |
) |
Crude oil (MBbl) |
|
|
0.3 |
|
|
6.93 |
|
|
|
2.3 |
|
|
0.3 |
|
|
15.72 |
|
|
4.4 |
|
|
|
(2.1 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
0.4 |
|
|
|
|
|
|
|
(0.1 |
) |
|
|
0.5 |
|
Ineffectiveness (3) |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
(0.3 |
) |
|
|
0.3 |
|
|
|
|
|
|
|
|
$ |
6.0 |
|
|
|
|
|
|
$ |
18.6 |
|
|
$ |
(12.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30, 2017 |
|
Six Months Ended
June 30, 2016 |
|
|
|
|
|
(In millions, except volumetric data and
price amounts) |
|
|
|
|
|
Volume
Settled |
|
Price
Spread
(1) |
|
Gain
(Loss) |
|
Volume
Settled |
|
Price
Spread
(1) |
|
Gain
(Loss) |
|
2017 vs.
2016 |
Natural gas (BBtu) |
|
|
26.0 |
|
$ |
0.09 |
|
|
$ |
2.6 |
|
|
20.2 |
|
$ |
1.33 |
|
$ |
26.9 |
|
|
$ |
(24.3 |
) |
NGL (MMgal) |
|
|
102.7 |
|
|
(0.01 |
) |
|
|
(1.1 |
) |
|
27.3 |
|
|
0.18 |
|
|
5.0 |
|
|
|
(6.1 |
) |
Crude oil (MBbl) |
|
|
0.6 |
|
|
6.29 |
|
|
|
3.5 |
|
|
0.5 |
|
|
23.82 |
|
|
11.5 |
|
|
|
(8.0 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
(0.3 |
) |
|
|
|
|
|
|
2.6 |
|
|
|
(2.9 |
) |
Ineffectiveness (3) |
|
|
|
|
|
|
|
0.2 |
|
|
|
|
|
|
|
(0.3 |
) |
|
|
0.5 |
|
|
|
|
|
|
|
|
$ |
4.9 |
|
|
|
|
|
|
$ |
45.7 |
|
|
$ |
(40.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The price spread is the differential between the
contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. |
(2) Mark-to-market income (loss) associated with
derivative contracts that are not designated as hedges for accounting purposes. |
(3) Ineffectiveness primarily relates to certain crude
hedging contracts and certain acquired hedges of Targa Pipeline Partners, L.P. (“TPL”) that do not qualify for hedge
accounting. |
As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015
(the “acquisition date”), were novated to the Company and included in the acquisition date fair value of assets acquired. The
Company received derivative settlements of $1.9 million and $4.9 million for the three and six months ended June 30, 2017 and $6.3
million and $15.1 million for the three and six months ended June 30, 2016, related to these novated contracts. From the
acquisition date through June 30, 2017, the Company has received total derivative settlements of $99.5 million. The remainder of
the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair
value of the TPL derivative assets acquired and had no effect on results of operations.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent
midstream energy companies in North America. Targa owns, operates, acquires, and develops a diversified portfolio of complementary
midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and
selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG
exporters; gathering, storing, and terminaling crude oil; and storing, terminaling, and selling refined petroleum products.
For more information, please visit our website at www.targaresources.com.
Targa Resources Corp. - Non-GAAP Financial Measures
This press release includes the Company’s non-GAAP financial measures Adjusted EBITDA, distributable cash flow,
gross margin and operating margin. The tables below provide reconciliations of these non-GAAP financial measures to their most
directly comparable GAAP measures. The Company’s non-GAAP financial measures should not be considered as alternatives to GAAP
measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of
liquidity or financial performance.
Adjusted EBITDA
The Company defines Adjusted EBITDA as net income (loss) available to TRC before: interest; income taxes;
depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and
early debt extinguishments and asset disposals; risk management activities related to derivative instruments including the cash
impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on
equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment (explained below); net income
attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions
from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and
amortization expense. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the
Company’s financial statements such as investors, commercial banks and others. The economic substance behind the
Company’s use of Adjusted EBITDA is to measure the ability of its assets to generate cash sufficient to pay interest costs,
support its indebtedness and pay dividends to its investors.
Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is
net income (loss) attributable to TRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted
EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a
substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items
that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of
Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable
GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making
processes.
Distributable Cash Flow
The Company defines distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited
partners, the Splitter Agreement adjustment (explained below), cash interest expense on debt obligations, cash tax (expense)
benefit and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of
noncontrolling interests on the prior adjustment items.
Distributable cash flow is a significant performance metric used by the Company and by external users of the
Company’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by
the Company (prior to the establishment of any retained cash reserves by our board of directors) to the cash dividends the Company
expects to pay its shareholders. Using this metric, management and external users of the Company’s financial statements can quickly
compute the coverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial
measure for the Company’s shareholders since it serves as an indicator of the Company’s success in providing a cash return on
investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a
level that can sustain or support an increase in its quarterly dividend rates.
Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to
distributable cash flow is net income (loss) attributable to TRC. Distributable cash flow should not be considered as an
alternative to GAAP net income (loss) available to common and preferred shareholders. It has important limitations as an analytical
tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported
under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by
different companies in the Company’s industry, the Company’s definition of distributable cash flow may not be comparable to
similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the
comparable GAAP measure, understanding the differences between the measures and incorporating these insights into our
decision-making processes.
The following table presents a reconciliation of net income of the Company to Adjusted EBITDA and Distributable
Cash Flow for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended June
30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In
millions)
|
|
Reconciliation of Net Income (Loss) attributable to TRC to
Adjusted EBITDA and Distributable Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRC |
|
$ |
57.6 |
|
|
$ |
(23.2 |
) |
|
$ |
(61.7 |
) |
|
$ |
(25.9 |
) |
|
Impact of TRC/TRP Merger on NCI |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(3.8 |
) |
|
Income attributable to TRP preferred limited partners |
|
|
2.8 |
|
|
|
2.8 |
|
|
|
5.6 |
|
|
|
5.6 |
|
|
Interest expense, net |
|
|
62.1 |
|
|
|
71.4 |
|
|
|
125.1 |
|
|
|
124.3 |
|
|
Income tax expense (benefit) |
|
|
(106.0 |
) |
|
|
1.7 |
|
|
|
(34.9 |
) |
|
|
4.8 |
|
|
Depreciation and amortization expense |
|
|
203.4 |
|
|
|
186.1 |
|
|
|
394.6 |
|
|
|
379.6 |
|
|
Goodwill impairment |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
24.0 |
|
|
(Gain) loss on sale or disposition of assets |
|
|
0.1 |
|
|
|
— |
|
|
|
16.2 |
|
|
|
0.9 |
|
|
(Gain) loss from financing activities |
|
|
10.7 |
|
|
|
3.3 |
|
|
|
16.5 |
|
|
|
(21.4 |
) |
|
(Earnings) loss from unconsolidated affiliates |
|
|
4.2 |
|
|
|
4.4 |
|
|
|
16.8 |
|
|
|
9.2 |
|
|
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
|
6.2 |
|
|
|
3.0 |
|
|
|
10.4 |
|
|
|
8.8 |
|
|
Change in contingent consideration included in Other expense |
|
|
(2.1 |
) |
|
|
— |
|
|
|
1.2 |
|
|
|
— |
|
|
Compensation on equity grants |
|
|
10.7 |
|
|
|
7.2 |
|
|
|
21.5 |
|
|
|
15.2 |
|
|
Transaction costs related to business acquisitions |
|
|
0.1 |
|
|
|
— |
|
|
|
5.2 |
|
|
|
— |
|
|
Splitter Agreement (1) |
|
|
10.8 |
|
|
|
— |
|
|
|
21.5 |
|
|
|
— |
|
|
Risk management activities |
|
|
1.6 |
|
|
|
6.6 |
|
|
|
5.2 |
|
|
|
12.6 |
|
|
Noncontrolling interests adjustments (2) |
|
|
(4.3 |
) |
|
|
(6.2 |
) |
|
|
(8.6 |
) |
|
|
(12.1 |
) |
|
TRC Adjusted EBITDA |
|
$ |
257.9 |
|
|
$ |
257.1 |
|
|
$ |
534.6 |
|
|
$ |
521.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to TRP preferred limited partners |
|
|
(2.8 |
) |
|
|
(2.8 |
) |
|
|
(5.6 |
) |
|
|
(5.6 |
) |
|
Splitter Agreement (1) |
|
|
(10.8 |
) |
|
|
— |
|
|
|
(21.5 |
) |
|
|
— |
|
|
Interest expense on debt obligations (3) |
|
|
(56.6 |
) |
|
|
(65.9 |
) |
|
|
(115.5 |
) |
|
|
(135.6 |
) |
|
Cash tax (expense) benefit (4) |
|
|
31.4 |
|
|
|
— |
|
|
|
46.7 |
|
|
|
— |
|
|
Maintenance capital expenditures |
|
|
(23.3 |
) |
|
|
(20.2 |
) |
|
|
(49.0 |
) |
|
|
(35.2 |
) |
|
Noncontrolling interests adjustments of maintenance capex |
|
|
0.2 |
|
|
|
1.4 |
|
|
|
0.5 |
|
|
|
2.2 |
|
|
Distributable Cash Flow |
|
$ |
196.0 |
|
|
$ |
169.6 |
|
|
$ |
390.2 |
|
|
$ |
347.6 |
|
|
_________________________________________ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) In Adjusted EBITDA, the Splitter Agreement adjustment
represents the recognition of the annual cash payment received under the condensate splitter agreement (the “Splitter
Agreement”) between Targa Terminals, LLC and Noble Americas Corp., a subsidiary of Noble Group, Ltd., over the four quarters
following receipt. In Distributable Cash Flow, the Splitter Agreement adjustment represents the amounts necessary to reflect
the annual cash payment in the period received less the amount recognized in Adjusted EBITDA. |
(2) Noncontrolling interest portion of depreciation and
amortization expense. |
(3) Excludes amortization of interest expense. |
(4) Includes an adjustment, reflecting the benefit from net
operating loss carryback to 2015 and 2014, which is being recognized over the periods between the Q3 2016 recognition of the
receivable and the anticipated receipt date of the refund. The refund, previously expected to be received on or before Q4 2017,
was received in Q2 2017. The remaining $20.9 million unamortized balance of the tax refund was therefore included in
Distributable Cash Flow in the second quarter of 2017. Also includes a refund of Texas margin tax paid in previous periods and
received in 2017. |
|
Gross Margin
The Company defines gross margin as revenues less product purchases. It is impacted by volumes and commodity
prices as well as by the Company’s contract mix and commodity hedging program.
Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas,
condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer
payments and other natural gas and crude oil purchases.
Logistics and Marketing segment gross margin consists primarily of:
- service fee revenues (including the pass-through of energy costs included in fee rates),
- system product gains and losses, and
- NGL and natural gas sales less NGL and natural gas purchases, transportation costs and the net inventory change.
The gross margin impacts of cash flow hedge settlements are reported in Other.
Operating Margin
The Company defines operating margin as gross margin less operating expenses. Operating margin is an important
performance measure of the core profitability of its operations.
Management reviews business segment gross margin and operating margin monthly as a core internal management
process. The Company believes that investors benefit from having access to the same financial measures that management uses in
evaluating its operating results. Gross margin and operating margin provide useful information to investors because they are used
as supplemental financial measures by management and by external users of the Company’s financial statements, including investors
and commercial banks, to assess:
- the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost
basis;
- the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector,
without regard to financing or capital structure; and
- the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment
opportunities.
Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross
margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have
important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a
substitute for analysis of the Company’s results as reported under GAAP. Because gross margin and operating margin exclude some,
but not all, items that affect net income and are defined differently by different companies in the Company’s industry, the
Company’s definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies,
thereby diminishing their utility.
Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing
the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its
decision-making processes.
The following table presents a reconciliation of net income to operating margin and gross margin for the periods
indicated:
|
|
Three Months Ended
June 30, |
|
Six Months Ended June
30, |
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
(In millions) |
Reconciliation of Net Income (Loss) attributable to TRC to
Operating Margin and Gross Margin: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRC |
|
$ |
57.6 |
|
|
$ |
(23.2 |
) |
|
$ |
(61.7 |
) |
|
$ |
(25.9 |
) |
Net income (loss) attributable to noncontrolling interests |
|
|
13.0 |
|
|
|
8.6 |
|
|
|
21.8 |
|
|
|
10.7 |
|
Net income (loss) |
|
|
70.6 |
|
|
|
(14.6 |
) |
|
|
(39.9 |
) |
|
|
(15.2 |
) |
Depreciation and amortization expense |
|
|
203.4 |
|
|
|
186.1 |
|
|
|
394.6 |
|
|
|
379.6 |
|
General and administrative expense |
|
|
51.0 |
|
|
|
47.0 |
|
|
|
99.6 |
|
|
|
92.2 |
|
Goodwill impairment |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
24.0 |
|
Interest expense, net |
|
|
62.1 |
|
|
|
71.4 |
|
|
|
125.1 |
|
|
|
124.3 |
|
Income tax expense (benefit) |
|
|
(106.0 |
) |
|
|
1.7 |
|
|
|
(34.9 |
) |
|
|
4.8 |
|
(Gain) loss on sale or disposition of assets |
|
|
0.1 |
|
|
|
— |
|
|
|
16.2 |
|
|
|
0.9 |
|
(Gain) loss from financing activities |
|
|
10.7 |
|
|
|
3.3 |
|
|
|
16.5 |
|
|
|
(21.4 |
) |
Other, net |
|
|
— |
|
|
|
4.6 |
|
|
|
21.1 |
|
|
|
9.6 |
|
Operating margin |
|
|
291.9 |
|
|
|
299.5 |
|
|
|
598.3 |
|
|
|
598.8 |
|
Operating expenses |
|
|
155.2 |
|
|
|
138.9 |
|
|
|
307.2 |
|
|
|
271.0 |
|
Gross margin |
|
$ |
447.1 |
|
|
$ |
438.4 |
|
|
$ |
905.5 |
|
|
$ |
869.8 |
|
Forward-Looking Statements
Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this release that address activities, events or developments that the Company expects,
believes or anticipates will or may occur in the future, are forward-looking statements. These forward-looking statements rely on a
number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are
outside the Company’s control, which could cause results to differ materially from those expected by management of the Company.
Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a
decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of business
development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully
in the Company’s filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended
December 31, 2016, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not
undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or
otherwise.
Contact investor relations by phone at (713) 584-1133. Sanjay Lad Director – Investor Relations Jennifer Kneale Vice President – Finance
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