Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or
“Targa”) today reported second quarter 2019 results.
Second Quarter 2019 Financial
Results
Second quarter 2019 net income (loss)
attributable to Targa Resources Corp. was ($10.2) million compared
to $109.1 million for the second quarter of 2018.
The Company reported quarterly earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“Adjusted EBITDA”) of $306.5 million for the second
quarter of 2019 compared to $315.2 million for the second
quarter of 2018 (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 results are in-line with our
expectations as our Gathering and Processing and Downstream systems
continued to perform very well,” said Joe Bob Perkins, Chief
Executive Officer of the Company. “Our Grand Prix NGL pipeline
recently commenced deliveries into Mont Belvieu, realizing the
long-run strategic goal of integrating our leading gathering and
processing position with our premier NGL logistics, fractionation
and export platform. Grand Prix, combined with our remaining system
expansions underway, will drive increasing, largely fee-based, cash
flow growth for Targa.”
On July 17, 2019, TRC declared a quarterly
dividend of $0.91 per share of its common stock for the
three months ended June 30, 2019, or $3.64 per share on
an annualized basis. Total cash dividends of approximately $211.5
million will be paid on August 15, 2019 on all
outstanding shares of common stock to holders of record as of the
close of business on July 31, 2019. Also, on
July 17, 2019, TRC declared a quarterly cash dividend of
$23.75 per share of its Series A Preferred Stock. Total cash
dividends of approximately $22.9 million will be paid on August 14,
2019 on all outstanding shares of Series A Preferred Stock to
holders of record as of the close of business on July 31, 2019.
The Company reported distributable cash flow for
the second quarter of 2019 of $192.0 million compared to total
common dividends to be paid of $211.5 million and total Series A
Preferred Stock dividends to be paid of $22.9 million.
Second Quarter 2019 - Sequential Quarter
over Quarter Commentary
Second quarter 2019 Adjusted EBITDA of $306.5
million was only 2 percent lower than the first quarter of 2019 as
strong fundamentals for Targa’s Gathering and Processing and
Downstream businesses offset the sale of the 45 percent interest in
Targa Badlands LLC (“Targa Badlands”), which closed April 3, 2019.
Strong volume performance led by higher sequential volumes in the
Permian region, higher fractionation volumes and higher liquefied
petroleum gas (“LPG”) export volumes would have resulted in higher
sequential Adjusted EBITDA if not for the Badlands sale. Increased
volumes in many of our businesses were partially offset by
lower commodity price realizations and higher operating expenses
attributable to Permian and Downstream system expansions.
Sequential realized Waha natural gas prices and natural gas liquids
(“NGL”) prices declined significantly, partially offset by higher
realized hedge gains, which are presented in Other, in the second
quarter versus the first quarter. Sequential operating expenses
were higher in the Gathering and Processing segment and the
Downstream segment, primarily associated with new assets coming
online and other system expansions that have driven labor costs
higher in advance of full quarter contributions of Adjusted EBITDA.
Please refer to the Company's second quarter 2019 Earnings
Supplement presentation, which can be accessed through the Events
and Presentations section of Targa’s website at
www.targaresources.com, for additional details.
Second Quarter 2019 - Capitalization and
Liquidity
The Company’s total consolidated debt as of June
30, 2019 was $6,948.3 million including $435.0 million
outstanding under TRC’s $670.0 million senior secured revolving
credit facility. The consolidated debt included $6,513.3 million of
Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt,
net of $41.9 million of debt issuance costs, with $190.0 million
outstanding under TRP’s $2.2 billion senior secured revolving
credit facility, $298.3 million outstanding under TRP’s accounts
receivable securitization facility, $6,028.2 million of outstanding
TRP senior notes, net of unamortized premiums, and $38.4 million of
finance lease liabilities.
Total consolidated liquidity of the Company as
of June 30, 2019, including $226.5 million of cash, was over $2.4
billion. As of June 30, 2019, TRC had available borrowing
capacity under its senior secured revolving credit facility of
$235.0 million. TRP had $190.0 million of borrowings and $66.0
million in letters of credit outstanding under its $2.2 billion
senior secured revolving credit facility, resulting in available
senior secured revolving credit facility capacity of $1,944.0
million.
Growth Projects Update
Since the end of the first quarter 2019, the Company has
completed and commenced operations on a number of its major growth
projects, aggregating to approximately $3 billion of growth capital
projects placed in-service, including:
- 250 million cubic feet per day (“MMcf/d”) Hopson Plant in
Permian-Midland;
- 100 thousand barrels per day (“MBbl/d”) Train 6 fractionator
in Mont Belvieu;
- 20-inch NGL pipeline from Mont Belvieu to the Company’s Galena
Park Marine Terminal;
- 200 MMcf/d Little Missouri 4 Plant in Badlands;
- Grand Prix NGL pipeline (“Grand Prix”) with service into Mont
Belvieu; and
- 250 MMcf/d Pembrook Plant in Permian-Midland (in
start-up).
Grand Prix recently commenced full operations, consistently
flowing between 150 to 170 thousand barrels per day to Mont
Belvieu. Our expectation is for volumes to increase to
approximately 200 thousand barrels per day in September, then
further increase over the balance of 2019 as short-term third party
transportation arrangements continue to roll off and additional
gathering and processing facilities come online. Grand Prix will
provide some partial margin contribution in the third quarter, and
as volumes continue to increase, the fourth quarter will be the
first full quarter of margin contribution.
As a result of longer than anticipated time related to
permitting, coupled with weather related construction delays during
critical periods, Grand Prix came online about two months delayed
and costs were approximately 10 percent higher than our initial
estimates provided over two years ago. Additionally, over the past
year we have experienced higher labor costs that have increased the
cost of recently completed gas processing plant expansions and
those underway.
2019 Financial and Operational
Expectations
Targa affirms its previously disclosed full year
financial and operational outlook for 2019, which assumes NGL
composite barrel prices average $0.60 per gallon, crude oil prices
average $54.00 per barrel and Henry Hub natural gas prices average
$3.00 per million British thermal units (“MMbtu”) for the year.
Year to date through the end of the second quarter, the Company
spent $1,372.6 million on net growth capital expenditures,
including net contributions to investments in unconsolidated
affiliates. The Permian Acquisition contingent consideration
earn-out period ended on February 28, 2019 and resulted in a $317.1
million payment in May 2019. Targa’s estimated 2019 net growth
capital expenditures is now expected to be approximately $2.4
billion, driven by the aforementioned project cost increases.
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 8, 2019 to discuss second quarter 2019
results. The conference call can be accessed via webcast through
the Events and Presentations section of Targa’s website at
www.targaresources.com, by going directly to
https://edge.media-server.com/mmc/p/mxbp2isk or by dialing
877-881-2598. The conference ID number for the dial-in is 5635187.
Please dial in ten minutes prior to the scheduled start time. A
webcast replay will be available at the link above approximately
two hours after the conclusion of the event.
Targa Resources Corp. – Consolidated Financial Results
of Operations
|
Three Months Ended June 30, |
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
(In millions) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
1,684.2 |
|
|
$ |
2,154.1 |
|
|
$ |
(469.9 |
) |
(22 |
%) |
|
$ |
3,660.7 |
|
|
$ |
4,327.4 |
|
|
$ |
(666.7 |
) |
(15 |
%) |
Fees from midstream services |
|
311.1 |
|
|
|
290.3 |
|
|
|
20.8 |
|
7 |
% |
|
|
634.0 |
|
|
|
572.6 |
|
|
|
61.4 |
|
11 |
% |
Total revenues |
|
1,995.3 |
|
|
|
2,444.4 |
|
|
|
(449.1 |
) |
(18 |
%) |
|
|
4,294.7 |
|
|
|
4,900.0 |
|
|
|
(605.3 |
) |
(12 |
%) |
Product purchases |
|
1,361.6 |
|
|
|
1,905.3 |
|
|
|
(543.7 |
) |
(29 |
%) |
|
|
3,087.6 |
|
|
|
3,846.2 |
|
|
|
(758.6 |
) |
(20 |
%) |
Gross margin (1) |
|
633.7 |
|
|
|
539.1 |
|
|
|
94.6 |
|
18 |
% |
|
|
1,207.1 |
|
|
|
1,053.8 |
|
|
|
153.3 |
|
15 |
% |
Operating expenses |
|
210.2 |
|
|
|
170.5 |
|
|
|
39.7 |
|
23 |
% |
|
|
400.5 |
|
|
|
343.7 |
|
|
|
56.8 |
|
17 |
% |
Operating margin (1) |
|
423.5 |
|
|
|
368.6 |
|
|
|
54.9 |
|
15 |
% |
|
|
806.6 |
|
|
|
710.1 |
|
|
|
96.5 |
|
14 |
% |
Depreciation and amortization
expense |
|
237.2 |
|
|
|
202.6 |
|
|
|
34.6 |
|
17 |
% |
|
|
474.6 |
|
|
|
400.7 |
|
|
|
73.9 |
|
18 |
% |
General and administrative
expense |
|
72.8 |
|
|
|
57.0 |
|
|
|
15.8 |
|
28 |
% |
|
|
153.6 |
|
|
|
113.8 |
|
|
|
39.8 |
|
35 |
% |
Other operating (income)
expense |
|
(0.2 |
) |
|
|
(46.4 |
) |
|
|
46.2 |
|
100 |
% |
|
|
3.3 |
|
|
|
(46.1 |
) |
|
|
49.4 |
|
107 |
% |
Income (loss) from
operations |
|
113.7 |
|
|
|
155.4 |
|
|
|
(41.7 |
) |
(27 |
%) |
|
|
175.1 |
|
|
|
241.7 |
|
|
|
(66.6 |
) |
(28 |
%) |
Interest income (expense),
net |
|
(72.1 |
) |
|
|
(62.0 |
) |
|
|
(10.1 |
) |
(16 |
%) |
|
|
(152.7 |
) |
|
|
(46.0 |
) |
|
|
(106.7 |
) |
(232 |
%) |
Equity earnings (loss) |
|
3.2 |
|
|
|
1.9 |
|
|
|
1.3 |
|
68 |
% |
|
|
5.9 |
|
|
|
3.4 |
|
|
|
2.5 |
|
74 |
% |
Gain (loss) from financing
activities |
|
— |
|
|
|
(2.0 |
) |
|
|
2.0 |
|
100 |
% |
|
|
(1.4 |
) |
|
|
(2.0 |
) |
|
|
0.6 |
|
30 |
% |
Change in contingent
considerations |
|
0.8 |
|
|
|
60.6 |
|
|
|
(59.8 |
) |
(99 |
%) |
|
|
(8.9 |
) |
|
|
4.5 |
|
|
|
(13.4 |
) |
(298 |
%) |
Income tax (expense)
benefit |
|
3.3 |
|
|
|
(32.8 |
) |
|
|
36.1 |
|
110 |
% |
|
|
6.2 |
|
|
|
(41.6 |
) |
|
|
47.8 |
|
115 |
% |
Net income (loss) |
|
48.9 |
|
|
|
121.1 |
|
|
|
(72.2 |
) |
(60 |
%) |
|
|
24.2 |
|
|
|
160.0 |
|
|
|
(135.8 |
) |
(85 |
%) |
Less: Net income (loss)
attributable to noncontrolling interests |
|
59.1 |
|
|
|
12.0 |
|
|
|
47.1 |
|
NM |
|
|
|
73.3 |
|
|
|
28.0 |
|
|
|
45.3 |
|
162 |
% |
Net income (loss) attributable
to Targa Resources Corp. |
|
(10.2 |
) |
|
|
109.1 |
|
|
|
(119.3 |
) |
(109 |
%) |
|
|
(49.1 |
) |
|
|
132.0 |
|
|
|
(181.1 |
) |
(137 |
%) |
Dividends on Series A
Preferred Stock |
|
22.9 |
|
|
|
22.9 |
|
|
|
— |
|
— |
|
|
|
45.8 |
|
|
|
45.8 |
|
|
|
— |
|
— |
|
Deemed dividends on Series A
Preferred Stock |
|
8.1 |
|
|
|
7.2 |
|
|
|
0.9 |
|
13 |
% |
|
|
16.0 |
|
|
|
14.1 |
|
|
|
1.9 |
|
13 |
% |
Net income (loss) attributable to common shareholders |
$ |
(41.2 |
) |
|
$ |
79.0 |
|
|
$ |
(120.2 |
) |
(152 |
%) |
|
$ |
(110.9 |
) |
|
$ |
72.1 |
|
|
$ |
(183.0 |
) |
(254 |
%) |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
306.5 |
|
|
$ |
315.2 |
|
|
$ |
(8.7 |
) |
(3 |
%) |
|
$ |
620.6 |
|
|
$ |
611.0 |
|
|
$ |
9.6 |
|
2 |
% |
Distributable cash flow
(1) |
|
192.0 |
|
|
|
225.1 |
|
|
|
(33.1 |
) |
(15 |
%) |
|
|
388.8 |
|
|
|
441.4 |
|
|
|
(52.6 |
) |
(12 |
%) |
Growth capital expenditures
(2) |
|
821.4 |
|
|
|
710.0 |
|
|
|
111.4 |
|
16 |
% |
|
|
1,691.5 |
|
|
|
1,245.6 |
|
|
|
445.9 |
|
36 |
% |
Maintenance capital
expenditures (3) |
|
35.5 |
|
|
|
24.8 |
|
|
|
10.7 |
|
43 |
% |
|
|
71.1 |
|
|
|
47.1 |
|
|
|
24.0 |
|
51 |
% |
___________________________________ |
(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) Growth
capital expenditures, net of contributions from noncontrolling
interest, were $1,315.3 million and $993.9 million for the six
months ended June 30, 2019 and 2018. Net contributions to
investments in unconsolidated affiliates were $57.3 million and
$62.2 million for the six months ended June 30, 2019 and 2018. |
(3)
Maintenance capital expenditures, net of contributions from
noncontrolling interests, were $67.2 million and $46.0 million for
the six months ended June 30, 2019 and 2018. |
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, 2019 Compared to Three Months Ended
June 30, 2018
The decrease in commodity sales reflects lower
NGL, natural gas, and condensate prices ($859.1 million) partially
offset by higher NGL, natural gas and crude marketing volumes
($340.9 million) and the favorable impact of hedges ($52.1
million). Higher exports, crude gathering and fractionation fees
resulted in increased fee-based revenues.
The decrease in product purchases reflects
decreased NGL, natural gas and condensate prices, partially offset
by increases in volumes.
Higher 2019 operating margin and gross margin
reflect increased segment results for Gathering and Processing and
Logistics and Marketing. See “Review of Segment Performance” for
additional information regarding changes in operating margin and
gross margin on a segment basis.
Depreciation and amortization expense increased
primarily due to higher depreciation related to major growth
projects placed in service, including additional processing plants
and associated infrastructure in the Permian Basin, the Permian
Basin Segment of Grand Prix, and Train 6. The increase is partially
offset by lower depreciation for the Company's downstream
facilities, resulting from the sale of certain petroleum logistics
storage and terminaling facilities in the fourth quarter of
2018.
General and administrative expense increased
primarily due to higher compensation and benefits, higher system
costs and increased outside professional services.
Interest expense, net, increased due to higher
average borrowings, partially offset by higher capitalized interest
related to the Company's major growth investments.
During 2019, the Permian Acquisition contingent
consideration earn-out period ended and resulted in a final payment
in May. During 2018, the Company recorded income of $60.6 million
resulting primarily from the decrease in fair value of the
contingent consideration liability. The fair value change was
primarily related to a decrease in underlying forecasted volumes
for the remainder of the earn-out period and a shorter term over
which such projections are discounted.
The change in income tax (expense) benefit was
primarily due to lower net income before tax and a lower annual
effective tax rate.
Six Months Ended June 30, 2019 Compared to Six
Months Ended June 30, 2018
The decrease in commodity sales reflects lower
NGL, natural gas and condensate prices ($1,335.0 million) and lower
petroleum products volumes due to the sale of certain petroleum
logistics storage and terminaling facilities in the fourth quarter
of 2018 ($29.5 million), partially offset by higher NGL, crude
marketing and natural gas volumes ($621.1 million) and the
favorable impact of hedges ($102.6 million). Higher exports and
crude gathering fees resulted in increased fee-based revenues.
The decrease in product purchases reflects
decreased NGL, natural gas and condensate prices, partially offset
by increases in volumes.
Higher 2019 operating margin and gross margin
reflect increased segment results for Gathering and Processing and
Logistics and Marketing. See “Review of Segment Performance” for
additional information regarding changes in operating margin and
gross margin on a segment basis.
Depreciation and amortization expense increased
primarily due to higher depreciation related to major growth
projects placed in service, including additional processing plants
and associated infrastructure in the Permian Basin, and the Permian
Basin Segment of Grand Prix. The increase is partially offset by
lower depreciation for the Company's downstream facilities,
resulting from the sale of certain petroleum logistics storage and
terminaling facilities in the fourth quarter of 2018.
General and administrative expense increased
primarily due to higher compensation and benefits, higher system
costs and increased outside professional services.
Interest expense, net, increased due to higher
average borrowings, partially offset by higher capitalized interest
related to the Company's major growth investments. During 2018, the
Company recognized non-cash interest income resulting from a
decrease in the estimated redemption value of the mandatorily
redeemable interests, primarily attributable to the February 2018
amendments to such arrangements.
During 2019, the Company recorded expense of
$8.9 million, resulting primarily from an increase in value of the
Permian Acquisition contingent consideration. During 2018, the
Company recorded income of $4.5 million resulting from the change
in the fair value of contingent considerations.
The change in income tax (expense) benefit was
primarily due to lower net income before tax, a lower annual
effective tax rate and higher tax benefits related to share-based
payment awards that vested during the period.
Review of Segment
Performance
The following discussion of segment performance
includes inter-segment activities. The Company views segment
operating margin and gross margin as important performance measures
of the core profitability of its operations. These measures are key
components of internal financial reporting and are reviewed for
consistency and trend analysis. For a discussion of operating
margin and gross margin, see “Targa Resources Corp. - Non-GAAP
Financial Measures - Operating Margin” and “Targa Resources Corp. -
Non-GAAP Financial Measures - Gross Margin.” Segment operating
financial results and operating statistics include the effects of
intersegment transactions. These intersegment transactions have
been eliminated from the consolidated presentation.
The Company operates in two primary segments:
(i) Gathering and Processing; and (ii) Logistics and Marketing.
Gathering and Processing
Segment
The Gathering and Processing segment includes
assets used in the gathering of natural gas produced from oil and
gas wells and processing this raw natural gas into merchantable
natural gas by extracting NGLs and removing impurities; and assets
used for crude oil gathering and terminaling. The Gathering and
Processing segment's assets are located in the Permian Basin of
West Texas and Southeast New Mexico (including the Midland and
Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett
Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in
Oklahoma (including the SCOOP and STACK) 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, |
|
|
|
|
|
|
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
2019 |
|
|
2018 |
|
|
|
2019 vs. 2018 |
|
|
(In millions, except operating statistics and price
amounts) |
|
Gross margin |
$ |
324.8 |
|
|
$ |
346.9 |
|
|
$ |
(22.1 |
) |
(6 |
%) |
|
$ |
677.0 |
|
|
$ |
672.6 |
|
|
$ |
4.4 |
|
1 |
% |
Operating expenses |
|
131.7 |
|
|
|
104.7 |
|
|
|
27.0 |
|
26 |
% |
|
|
254.8 |
|
|
|
209.4 |
|
|
|
45.4 |
|
22 |
% |
Operating margin |
$ |
193.1 |
|
|
$ |
242.2 |
|
|
$ |
(49.1 |
) |
(20 |
%) |
|
$ |
422.2 |
|
|
$ |
463.2 |
|
|
$ |
(41.0 |
) |
(9 |
%) |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
1,432.6 |
|
|
|
1,125.1 |
|
|
|
307.5 |
|
27 |
% |
|
|
1,383.7 |
|
|
|
1,069.9 |
|
|
|
313.8 |
|
29 |
% |
Permian Delaware |
|
545.1 |
|
|
|
417.3 |
|
|
|
127.8 |
|
31 |
% |
|
|
513.0 |
|
|
|
413.3 |
|
|
|
99.7 |
|
24 |
% |
Total Permian |
|
1,977.7 |
|
|
|
1,542.4 |
|
|
|
435.3 |
|
|
|
|
|
1,896.7 |
|
|
|
1,483.2 |
|
|
|
413.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
313.8 |
|
|
|
413.5 |
|
|
|
(99.7 |
) |
(24 |
%) |
|
|
338.7 |
|
|
|
414.9 |
|
|
|
(76.2 |
) |
(18 |
%) |
North Texas |
|
224.0 |
|
|
|
246.1 |
|
|
|
(22.1 |
) |
(9 |
%) |
|
|
227.2 |
|
|
|
240.6 |
|
|
|
(13.4 |
) |
(6 |
%) |
SouthOK (6) |
|
607.7 |
|
|
|
549.9 |
|
|
|
57.8 |
|
11 |
% |
|
|
613.8 |
|
|
|
539.9 |
|
|
|
73.9 |
|
14 |
% |
WestOK |
|
338.2 |
|
|
|
348.2 |
|
|
|
(10.0 |
) |
(3 |
%) |
|
|
338.2 |
|
|
|
349.1 |
|
|
|
(10.9 |
) |
(3 |
%) |
Total Central |
|
1,483.7 |
|
|
|
1,557.7 |
|
|
|
(74.0 |
) |
|
|
|
|
1,517.9 |
|
|
|
1,544.5 |
|
|
|
(26.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (7), (8) |
|
92.3 |
|
|
|
85.9 |
|
|
|
6.4 |
|
7 |
% |
|
|
94.6 |
|
|
|
79.7 |
|
|
|
14.9 |
|
19 |
% |
Total Field |
|
3,553.7 |
|
|
|
3,186.0 |
|
|
|
367.7 |
|
|
|
|
|
3,509.2 |
|
|
|
3,107.4 |
|
|
|
401.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
804.9 |
|
|
|
665.3 |
|
|
|
139.6 |
|
21 |
% |
|
|
787.5 |
|
|
|
694.6 |
|
|
|
92.9 |
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
4,358.6 |
|
|
|
3,851.3 |
|
|
|
507.3 |
|
13 |
% |
|
|
4,296.7 |
|
|
|
3,802.0 |
|
|
|
494.7 |
|
13 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
198.0 |
|
|
|
151.4 |
|
|
|
46.6 |
|
31 |
% |
|
|
191.3 |
|
|
|
145.9 |
|
|
|
45.4 |
|
31 |
% |
Permian Delaware |
|
71.4 |
|
|
|
50.3 |
|
|
|
21.1 |
|
42 |
% |
|
|
65.9 |
|
|
|
48.0 |
|
|
|
17.9 |
|
37 |
% |
Total Permian |
|
269.4 |
|
|
|
201.7 |
|
|
|
67.7 |
|
|
|
|
|
257.2 |
|
|
|
193.9 |
|
|
|
63.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
41.7 |
|
|
|
54.5 |
|
|
|
(12.8 |
) |
(23 |
%) |
|
|
45.2 |
|
|
|
54.3 |
|
|
|
(9.1 |
) |
(17 |
%) |
North Texas |
|
26.6 |
|
|
|
28.8 |
|
|
|
(2.2 |
) |
(8 |
%) |
|
|
26.7 |
|
|
|
27.4 |
|
|
|
(0.7 |
) |
(3 |
%) |
SouthOK (6) |
|
68.3 |
|
|
|
51.1 |
|
|
|
17.2 |
|
34 |
% |
|
|
63.3 |
|
|
|
50.0 |
|
|
|
13.3 |
|
27 |
% |
WestOK |
|
23.8 |
|
|
|
19.5 |
|
|
|
4.3 |
|
22 |
% |
|
|
24.0 |
|
|
|
19.5 |
|
|
|
4.5 |
|
23 |
% |
Total Central |
|
160.4 |
|
|
|
153.9 |
|
|
|
6.5 |
|
|
|
|
|
159.2 |
|
|
|
151.2 |
|
|
|
8.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (8) |
|
11.3 |
|
|
|
10.8 |
|
|
|
0.5 |
|
5 |
% |
|
|
11.3 |
|
|
|
10.5 |
|
|
|
0.8 |
|
8 |
% |
Total Field |
|
441.1 |
|
|
|
366.4 |
|
|
|
74.7 |
|
|
|
|
|
427.7 |
|
|
|
355.6 |
|
|
|
72.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
47.3 |
|
|
|
38.3 |
|
|
|
9.0 |
|
23 |
% |
|
|
47.8 |
|
|
|
40.4 |
|
|
|
7.4 |
|
18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
488.4 |
|
|
|
404.7 |
|
|
|
83.7 |
|
21 |
% |
|
|
475.5 |
|
|
|
396.0 |
|
|
|
79.5 |
|
20 |
% |
Crude oil gathered, Badlands,
MBbl/d |
|
167.3 |
|
|
|
139.8 |
|
|
|
27.5 |
|
20 |
% |
|
|
168.4 |
|
|
|
128.8 |
|
|
|
39.6 |
|
31 |
% |
Crude oil gathered, Permian,
MBbl/d |
|
86.3 |
|
|
|
66.6 |
|
|
|
19.7 |
|
30 |
% |
|
|
81.4 |
|
|
|
58.0 |
|
|
|
23.4 |
|
40 |
% |
Natural gas sales, BBtu/d
(3) |
|
2,049.7 |
|
|
|
1,878.1 |
|
|
|
171.6 |
|
9 |
% |
|
|
1,988.1 |
|
|
|
1,823.0 |
|
|
|
165.1 |
|
9 |
% |
NGL sales, MBbl/d |
|
389.3 |
|
|
|
304.1 |
|
|
|
85.2 |
|
28 |
% |
|
|
374.5 |
|
|
|
302.0 |
|
|
|
72.5 |
|
24 |
% |
Condensate sales, MBbl/d |
|
13.2 |
|
|
|
13.5 |
|
|
|
(0.3 |
) |
(2 |
%) |
|
|
12.8 |
|
|
|
12.8 |
|
|
|
- |
|
- |
|
Average realized
prices (9): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
0.73 |
|
|
|
1.82 |
|
|
|
(1.09 |
) |
(60 |
%) |
|
|
1.29 |
|
|
|
2.09 |
|
|
|
(0.80 |
) |
(38 |
%) |
NGL, $/gal |
|
0.33 |
|
|
|
0.66 |
|
|
|
(0.33 |
) |
(50 |
%) |
|
|
0.39 |
|
|
|
0.63 |
|
|
|
(0.24 |
) |
(38 |
%) |
Condensate, $/Bbl |
|
51.34 |
|
|
|
58.23 |
|
|
|
(6.89 |
) |
(12 |
%) |
|
|
49.29 |
|
|
|
58.58 |
|
|
|
(9.29 |
) |
(16 |
%) |
_____________________________ |
(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 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) Permian
Midland includes operations in WestTX, of which the Company owns
72.8%, and other plants that are owned 100% by us. Operating
results for the WestTX undivided interest assets are presented on a
pro-rata net basis in the Company's reported financials. |
(5) SouthTX
includes the Raptor Plant, of which the Company owns a 50% interest
through the Carnero Joint Venture. SouthTX also includes the Silver
Oak II Plant, of which the Company owned a 100% interest until it
was contributed to the Carnero Joint Venture in May 2018. The
Carnero Joint Venture is a consolidated subsidiary and its
financial results are presented on a gross basis in the Company's
reported financials. |
(6) SouthOK
includes the Centrahoma Joint Venture, of which the Company owns
60%, and other plants that are owned 100% by us. Centrahoma is a
consolidated subsidiary and its financial results are presented on
a gross basis in the Company's reported financials. |
(7)
Badlands natural gas inlet represents the total wellhead gathered
volume. |
(8) As of
April 3, 2019, Targa owns 55% of Targa Badlands through a joint
venture (the “Badlands Joint Venture”), prior to which the Company
owned a 100% interest. The Badlands Joint Venture is a consolidated
subsidiary and its financial results are presented on a gross basis
in the Company's reported financials. |
(9) Average
realized prices exclude the impact of hedging activities presented
in Other. |
Three Months Ended June 30, 2019 Compared to Three Months Ended
June 30, 2018
The decrease in gross margin was primarily due
to lower commodity prices, partially offset by higher Permian
volumes and higher Badlands fee-based volumes. Inlet volumes
increased significantly across both the Permian Midland and Permian
Delaware regions as a result of the Company's new gas plant
additions. The impact of lower commodity prices excludes the
benefit from the Company's hedging activities presented in Other.
NGL production, NGL sales and natural gas sales increased primarily
due to higher Gathering and Processing inlet volumes and increased
NGL recoveries. Total crude oil gathered volumes increased in both
the Permian region and the Badlands due to production from new
wells and system expansions.
The increase in operating expenses was primarily
driven by gas plant and system expansions in the Permian
region.
Six Months Ended June 30, 2019 Compared to Six
Months Ended June 30, 2018
Gross margin was relatively flat due to higher
Permian volumes and higher Badlands fee-based volumes, which were
offset by the impact of lower commodity prices. Plant inlet volumes
increased significantly across both the Permian Midland and Permian
Delaware regions as a result of the Company's new gas plant
additions. The impact of lower commodity prices excludes the
benefit from the Company's hedging activities presented in Other.
NGL production, NGL sales and natural gas sales increased primarily
due to higher Gathering and Processing inlet volumes and increased
NGL recoveries. Total crude oil gathered volumes increased in both
the Permian region and the Badlands due to production from new
wells and system expansions.
The increase in operating expenses was primarily
driven by gas plant and system expansions in the Permian
region.
Logistics and Marketing
Segment
The Logistics and Marketing segment includes the
activities and assets necessary to convert mixed NGLs into NGL
products and also includes other assets and value-added services
such as transporting, storing, fractionating, terminaling and
marketing of NGLs and NGL products, including services to liquefied
petroleum gas (“LPG”) exporters; storing and terminaling of refined
petroleum products and crude oil and certain natural gas supply and
marketing activities in support of the Company’s other businesses.
The Logistics and Marketing segment also includes Grand Prix, which
integrates the Company’s gathering and processing positions in the
Permian Basin, Southern Oklahoma and North Texas with the Company’s
downstream facilities in Mont Belvieu, Texas. The associated assets
are generally connected to and supplied in part by the Company’s
Gathering and Processing segment and, except for pipelines and
smaller terminals, are located predominantly in Mont Belvieu and
Galena Park, Texas, and in Lake Charles, Louisiana.
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, |
|
|
|
|
|
|
|
|
2019 |
|
2018 |
|
2019 vs. 2018 |
|
|
2019 |
|
2018 |
|
2019 vs. 2018 |
|
|
(In millions, except operating statistics and price
amounts) |
|
Gross margin |
$ |
262.5 |
|
$ |
196.9 |
|
$ |
65.6 |
|
33 |
% |
|
$ |
482.0 |
|
$ |
403.7 |
|
$ |
|
78.3 |
|
19 |
% |
Operating expenses |
|
78.1 |
|
|
67.0 |
|
|
11.1 |
|
17 |
% |
|
|
145.7 |
|
|
135.4 |
|
|
|
10.3 |
|
8 |
% |
Operating margin |
$ |
184.4 |
|
$ |
129.9 |
|
$ |
54.5 |
|
42 |
% |
|
$ |
336.3 |
|
$ |
268.3 |
|
$ |
|
68.0 |
|
25 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (2) |
|
512.5 |
|
|
412.2 |
|
|
100.3 |
|
24 |
% |
|
|
484.7 |
|
|
401.0 |
|
|
|
83.7 |
|
21 |
% |
Export
volumes (3) |
|
231.5 |
|
|
190.3 |
|
|
41.2 |
|
22 |
% |
|
|
222.4 |
|
|
196.1 |
|
|
|
26.3 |
|
13 |
% |
NGL sales |
|
605.2 |
|
|
509.3 |
|
|
95.9 |
|
19 |
% |
|
|
594.8 |
|
|
512.0 |
|
|
|
82.8 |
|
16 |
% |
Average realized
prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL realized price, $/gal |
$ |
0.50 |
|
$ |
0.76 |
|
$ |
(0.26 |
) |
(34 |
%) |
|
$ |
0.55 |
|
$ |
0.76 |
|
$ |
|
(0.21 |
) |
(28 |
%) |
____________________________________________ |
(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 contracts include pricing terms composed of base fees
and fuel and power components that 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. Fractionation volumes for 2019 reflect volumes
delivered and fractionated, whereas fractionation volumes for 2018
reflect volumes delivered and settled under fractionation
contracts. |
(3) 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. |
Three Months Ended June 30, 2019 Compared to
Three Months Ended June 30, 2018
Logistics and Marketing gross margin increased
due to higher transportation and fractionation margin, higher LPG
export margin, and higher marketing margin, partially offset by
lower terminaling and storage throughput. Transportation and
fractionation margin increased due to higher supply volume, the
commencement of Train 6 operations during the second quarter of
2019, and the start-up of portions of Grand Prix. Fractionation
margin was partially impacted by the variable effects of fuel and
power that are largely reflected in operating expenses (see
footnote (2) above). LPG export margin increased primarily due to
higher volumes, which included volumes deferred from the first
quarter to the second quarter of 2019 as a result of restrictions
and temporary closures of the Houston Ship Channel in the first
quarter. Marketing margin increased primarily due to optimization
of liquids arrangements. Terminaling and storage throughput
decreased due to the sale of certain petroleum logistics terminals
in the fourth quarter of 2018.
Operating expenses increased due to higher
compensation and benefits and higher taxes, primarily attributable
to the start-up of portions of Grand Prix and the commencement of
Train 6 operations, higher fuel and power costs and higher
maintenance, partially offset by decreases in expenses due to the
sale of certain petroleum logistics terminals in the fourth quarter
of 2018.
Six Months Ended June 30, 2019 Compared to Six
Months Ended June 30, 2018
Logistics and Marketing gross margin increased
due to higher LPG export margin, higher transportation and
fractionation margin, and higher marketing margin, partially offset
by lower terminaling and storage throughput. LPG export margin
increased primarily due to higher volumes. Transportation and
fractionation margin increased due to higher supply volume, the
start-up of portions of Grand Prix, and the commencement of Train 6
operations during the second quarter of 2019. Marketing margin
increased primarily due to optimization of liquids arrangements.
Terminaling and storage throughput decreased due to the sale of
certain petroleum logistics terminals in the fourth quarter of
2018.
Operating expenses increased due to higher
compensation and benefits and higher taxes primarily attributable
to the start-up of portions of Grand Prix and the commencement of
Train 6 operations, higher fuel and power costs and higher
maintenance, partially offset by decreases in expenses due to the
sale of certain petroleum logistics terminals in the fourth quarter
of 2018.
Other
|
|
Three Months Ended June 30, |
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
2019 |
|
2018 |
|
|
2019 vs. 2018 |
|
2019 |
|
2018 |
|
|
2019 vs. 2018 |
|
|
(In millions) |
Gross margin |
|
$ |
46.0 |
|
$ |
(3.5 |
) |
|
$ |
49.5 |
|
$ |
48.1 |
|
$ |
(21.4 |
) |
|
$ |
69.5 |
Operating margin |
|
$ |
46.0 |
|
$ |
(3.5 |
) |
|
$ |
49.5 |
|
$ |
48.1 |
|
$ |
(21.4 |
) |
|
$ |
69.5 |
Other contains the results of commodity
derivative activities related to Gathering and Processing hedges of
equity volumes that are included in operating margin and
mark-to-market gains/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 the
Company’s 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, 2019 |
|
|
Three Months Ended
June 30, 2018 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
16.1 |
|
$ |
1.97 |
|
|
$ |
31.8 |
|
|
17.0 |
|
$ |
1.01 |
|
|
$ |
17.1 |
|
NGL (MMgal) |
72.7 |
|
|
0.12 |
|
|
|
8.9 |
|
|
94.8 |
|
|
(0.15 |
) |
|
|
(14.0 |
) |
Crude oil (MBbl) |
0.4 |
|
|
(4.98 |
) |
|
|
(1.8 |
) |
|
0.5 |
|
|
(14.21 |
) |
|
|
(7.2 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
7.1 |
|
|
|
|
|
|
|
|
|
0.6 |
|
|
|
|
|
|
|
|
$ |
46.0 |
|
|
|
|
|
|
|
|
$ |
(3.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30, 2019 |
|
|
Six Months Ended
June 30, 2018 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
28.2 |
|
$ |
1.43 |
|
|
$ |
40.4 |
|
|
32.8 |
|
$ |
0.70 |
|
|
$ |
22.9 |
|
NGL (MMgal) |
142.1 |
|
|
0.07 |
|
|
|
9.4 |
|
|
187.3 |
|
|
(0.12 |
) |
|
|
(23.4 |
) |
Crude oil (MBbl) |
0.7 |
|
|
(2.58 |
) |
|
|
(1.8 |
) |
|
1.0 |
|
|
(11.72 |
) |
|
|
(11.8 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
(9.1 |
) |
|
|
|
|
|
|
|
$ |
48.1 |
|
|
|
|
|
|
|
|
$ |
(21.4 |
) |
_____________________________ |
(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. |
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. The Company 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,
transporting and selling natural gas; transporting, storing,
fractionating, treating and selling NGLs and NGL products,
including services to LPG exporters; and gathering, storing,
terminaling and selling crude oil.
For more information, please visit the Company’s
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 following tables
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) attributable to TRC before interest, income taxes,
depreciation and amortization, and other items that the Company
believes should be adjusted consistent with the Company’s core
operating performance. The adjusting items are detailed in the
Adjusted EBITDA reconciliation table and its footnotes. Adjusted
EBITDA is used as a supplemental financial measure by the Company
and by external users of its 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 the Company’s 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, its 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, cash interest expense on debt obligations, cash tax
(expense) benefit and maintenance capital expenditures (net of any
reimbursements of project costs).
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 it
(prior to the establishment of any retained cash reserves by the
Company’s board of directors) to the cash dividends the Company
expects to pay its shareholders. Using this metric, management and
external users of its 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 the Company’s 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 the Company’s
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, |
|
|
2019 |
|
|
2018 |
|
|
2019 |
|
|
2018 |
|
|
(In millions) |
|
Reconciliation of Net Income (Loss) attributable to TRC to
Adjusted EBITDA and Distributable Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRC |
$ |
(10.2 |
) |
|
$ |
109.1 |
|
|
$ |
(49.1 |
) |
|
$ |
132.0 |
|
Income attributable to TRP preferred limited partners |
|
2.8 |
|
|
|
2.8 |
|
|
|
5.6 |
|
|
|
5.6 |
|
Interest (income) expense, net (1) |
|
72.1 |
|
|
|
62.0 |
|
|
|
152.7 |
|
|
|
46.0 |
|
Income tax expense (benefit) |
|
(3.3 |
) |
|
|
32.8 |
|
|
|
(6.2 |
) |
|
|
41.6 |
|
Depreciation and amortization expense |
|
237.2 |
|
|
|
202.6 |
|
|
|
474.6 |
|
|
|
400.7 |
|
(Gain) loss on sale or disposition of assets |
|
(0.2 |
) |
|
|
(46.7 |
) |
|
|
3.1 |
|
|
|
(46.8 |
) |
(Gain) loss from financing activities (2) |
|
— |
|
|
|
2.0 |
|
|
|
1.4 |
|
|
|
2.0 |
|
Equity (earnings) loss |
|
(3.2 |
) |
|
|
(1.9 |
) |
|
|
(5.9 |
) |
|
|
(3.4 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
12.6 |
|
|
|
7.0 |
|
|
|
19.4 |
|
|
|
13.9 |
|
Change in contingent considerations |
|
(0.8 |
) |
|
|
(60.6 |
) |
|
|
8.9 |
|
|
|
(4.5 |
) |
Compensation on equity grants |
|
16.2 |
|
|
|
13.7 |
|
|
|
32.7 |
|
|
|
26.9 |
|
Risk management activities |
|
(7.1 |
) |
|
|
(0.6 |
) |
|
|
0.1 |
|
|
|
9.1 |
|
Noncontrolling interests adjustments (3) |
|
(9.6 |
) |
|
|
(7.0 |
) |
|
|
(16.7 |
) |
|
|
(12.1 |
) |
TRC Adjusted EBITDA (4) |
$ |
306.5 |
|
|
$ |
315.2 |
|
|
$ |
620.6 |
|
|
$ |
611.0 |
|
Distributions to TRP preferred limited partners |
|
(2.8 |
) |
|
|
(2.8 |
) |
|
|
(5.6 |
) |
|
|
(5.6 |
) |
Interest expense on debt obligations (5) |
|
(78.9 |
) |
|
|
(63.1 |
) |
|
|
(159.0 |
) |
|
|
(118.0 |
) |
Maintenance capital expenditures |
|
(35.5 |
) |
|
|
(24.8 |
) |
|
|
(71.1 |
) |
|
|
(47.1 |
) |
Noncontrolling interests adjustments of maintenance capital
expenditures |
|
2.7 |
|
|
|
0.6 |
|
|
|
3.9 |
|
|
|
1.1 |
|
Distributable Cash
Flow |
$ |
192.0 |
|
|
$ |
225.1 |
|
|
$ |
388.8 |
|
|
$ |
441.4 |
|
_____________________________ |
(1)
Includes the change in estimated redemption value of the
mandatorily redeemable preferred interests. |
(2) Gains
or losses on debt repurchases, amendments, exchanges or early debt
extinguishments. |
(3)
Noncontrolling interest portion of depreciation and amortization
expense. |
(4)
Beginning in the second quarter of 2019, the Company revised the
Company's reconciliation of Net Income (Loss) attributable to TRC
to Adjusted EBITDA to exclude the Splitter Agreement adjustment
previously included in the comparative periods presented herein.
For all comparative periods presented, the Company's Adjusted
EBITDA measure previously included the Splitter Agreement
adjustment, which represented the recognition of the annual cash
payment received under the condensate splitter agreement ratably
over four quarters. The effect of these revisions reduced TRC’s
Adjusted EBITDA by $10.8 million and $21.5 million for the three
and six months ended June 30, 2018. There was no impact to
Distributable Cash Flow. |
(5)
Excludes amortization of interest expense. |
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 less producer payments and other natural gas and crude oil
purchases; and
- service fees related to natural gas and crude oil gathering,
treating and processing.
Logistics and Marketing segment gross margin
consists primarily of:
- service fees (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 the Company’s equity
volumes 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 the Company’s
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 (loss) attributable to TRC.
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 of the Company to operating margin and
gross margin for the periods indicated:
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
2019 |
|
|
2018 |
|
|
2019 |
|
|
2018 |
|
|
(In millions) |
|
Reconciliation of Net Income (Loss) attributable to TRC to
Operating Margin and Gross Margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable
to TRC |
$ |
(10.2 |
) |
|
$ |
109.1 |
|
|
$ |
(49.1 |
) |
|
$ |
132.0 |
|
Net income (loss) attributable
to noncontrolling interests |
|
59.1 |
|
|
|
12.0 |
|
|
|
73.3 |
|
|
|
28.0 |
|
Net income (loss) |
|
48.9 |
|
|
|
121.1 |
|
|
|
24.2 |
|
|
|
160.0 |
|
Depreciation and amortization expense |
|
237.2 |
|
|
|
202.6 |
|
|
|
474.6 |
|
|
|
400.7 |
|
General and administrative expense |
|
72.8 |
|
|
|
57.0 |
|
|
|
153.6 |
|
|
|
113.8 |
|
Interest (income) expense, net |
|
72.1 |
|
|
|
62.0 |
|
|
|
152.7 |
|
|
|
46.0 |
|
Income tax expense (benefit) |
|
(3.3 |
) |
|
|
32.8 |
|
|
|
(6.2 |
) |
|
|
41.6 |
|
(Gain) loss on sale or disposition of assets |
|
(0.2 |
) |
|
|
(46.7 |
) |
|
|
3.1 |
|
|
|
(46.8 |
) |
(Gain) loss from financing activities |
|
— |
|
|
|
2.0 |
|
|
|
1.4 |
|
|
|
2.0 |
|
Change in contingent considerations |
|
(0.8 |
) |
|
|
(60.6 |
) |
|
|
8.9 |
|
|
|
(4.5 |
) |
Other, net |
|
(3.2 |
) |
|
|
(1.6 |
) |
|
|
(5.7 |
) |
|
|
(2.7 |
) |
Operating
margin |
|
423.5 |
|
|
|
368.6 |
|
|
|
806.6 |
|
|
|
710.1 |
|
Operating expenses |
|
210.2 |
|
|
|
170.5 |
|
|
|
400.5 |
|
|
|
343.7 |
|
Gross
margin |
$ |
633.7 |
|
|
$ |
539.1 |
|
|
$ |
1,207.1 |
|
|
$ |
1,053.8 |
|
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, 2018, 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 the Company's investor relations
department by email at InvestorRelations@targaresources.com or by
phone at (713) 584-1133.
Sanjay LadSenior Director, Finance &
Investor Relations
Jennifer KnealeChief Financial Officer
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