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
|
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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|
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|
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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 |
|
|
|
92.2 |
|
|
|
7.4 |
|
|
8 |
% |
Goodwill
impairment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
— |
|
|
|
— |
|
|
|
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 |
|
|
|
(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: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 EndedJune 30, |
|
|
|
|
Six Months EndedJune 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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