Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or
“Targa”) today reported third quarter 2019 results.
Third Quarter 2019 Financial
Results
Third quarter 2019 net loss attributable to
Targa Resources Corp. was $47.3 million compared to a net loss of
$23.7 million for the third quarter of 2018.
The Company reported quarterly earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“Adjusted EBITDA”) of $349.6 million for the third
quarter of 2019 compared to $347.2 million for the third
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 Gathering and Processing and Downstream
systems continued to perform very well, bolstered by the partial
quarter contribution of our recently completed Grand Prix NGL
Pipeline,” said Joe Bob Perkins, Chief Executive Officer of the
Company. “With the recent completion of Grand Prix and other
important growth projects, we are beginning to demonstrate the
strategic benefits of our premier integrated midstream position and
our cash flow profile is expected to strengthen meaningfully,
positioning Targa well over the long-term.”
On October 16, 2019, TRC declared a quarterly
dividend of $0.91 per share of its common stock for the
three months ended September 30, 2019, or $3.64 per
share on an annualized basis. Total cash dividends of approximately
$211.8 million will be paid on November 15, 2019 on all
outstanding shares of common stock to holders of record as of the
close of business on November 1, 2019. Also, on October
16, 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 November 14, 2019 on
all outstanding shares of Series A Preferred Stock to holders of
record as of the close of business on November 1, 2019.
The Company reported distributable cash flow for
the third quarter of 2019 of $229.9 million compared to total
common dividends to be paid of $211.8 million and total Series A
Preferred Stock dividends to be paid of $22.9 million, resulting in
dividend coverage of approximately 1.0 times.
Third Quarter 2019 - Sequential Quarter
over Quarter Commentary
Third quarter 2019 Adjusted EBITDA of $349.6
million was 14 percent higher than the second quarter of 2019,
driven by meaningful contributions from recently completed growth
projects in Targa’s Gathering and Processing and Downstream
segments. In the Gathering and Processing segment, strong volume
performance in the Permian region and the Badlands, combined with
lower operating expenses, was partially offset by lower natural gas
liquids (“NGL”) price realizations. Sequentially lower realized NGL
prices in the third quarter versus the second quarter were
partially offset by realized hedge gains, which are presented in
Other. Strong financial performance in the Downstream segment was
led by Targa’s Grand Prix NGL Pipeline (“Grand Prix”), which
commenced full operations into Mont Belvieu in August 2019. Grand
Prix deliveries into Mont Belvieu averaged approximately 230
thousand barrels per day in September 2019 and are expected to
further increase. Fractionation volumes in the third quarter were
flat relative to the second quarter as the Company completed a
scheduled turnaround and related maintenance, and Targa’s
fractionation complex in Mont Belvieu has since returned to
operating at a very high utilization rate. Higher sequential
operating expenses in the Downstream segment were attributable to a
full quarter of Train 6 operations and a partial quarter of full
operations of Grand Prix.
The Company has forward natural gas basis swaps
that do not qualify for hedge accounting treatment. As of September
30, 2019, the non-cash unrealized mark-to-market loss attributable
to the change in fair value of the financial instruments was $101.2
million. This unrealized mark-to-market loss is attributable to
unfavorable movements in forward natural gas basis prices and will
be more than offset by locked-in gains to be realized in future
periods from the underlying transportation arrangements.
Third Quarter 2019 - Capitalization and
Liquidity
The Company’s total consolidated debt as of
September 30, 2019 was $7,537.7 million including $435.0
million outstanding under TRC’s $670.0 million senior secured
revolving credit facility. The consolidated debt included $7,102.7
million of Targa Resources Partners LP’s (“TRP” or the
“Partnership”) debt, net of $40.7 million of debt issuance costs,
with $830.0 million outstanding under TRP’s $2.2 billion senior
secured revolving credit facility, $246.0 million outstanding under
TRP’s accounts receivable securitization facility, $6,028.5 million
of outstanding TRP senior notes, net of unamortized premiums, and
$38.9 million of finance lease liabilities.
Total consolidated liquidity of the Company as
of September 30, 2019, including $326.3 million of cash, was over
$1.8 billion. As of September 30, 2019, TRC had available
borrowing capacity under its senior secured revolving credit
facility of $235.0 million. TRP had $830.0 million of
borrowings and $73.8 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 $1,296.2 million.
Growth Projects Update
Since the beginning of 2019, the Company has
completed and commenced operations on numerous major growth
projects, aggregating to approximately $4.0 billion of growth
capital projects placed in-service. In addition to Grand Prix being
placed in-service during the third quarter, Targa also commenced
operations on its 200 million cubic feet per day (“MMcf/d”) Little
Missouri 4 Plant (“LM4 Plant”) in the Badlands, its 250
MMcf/d Pembrook Plant in Permian Midland and its 250 MMcf/d Falcon
Plant in Permian Delaware, and also completed a dock rebuild at its
LPG export facility in Galena Park.
The fourth quarter of 2019 will be the first
full quarter of margin contribution from Grand Prix, the LM4 Plant,
the Pembrook Plant, the Falcon Plant, and additional export
services capacity at Galena Park.
2019 Financial and Operational
Expectations and 2020 Preliminary Growth Capital
Outlook
Targa affirms its previously disclosed full year
financial and operational outlook for 2019, despite generally lower
year-to-date commodity prices versus original assumptions. Through
September 30, 2019, the Company spent $1,946.2 million on net
growth capital expenditures, including net contributions to
investments in unconsolidated affiliates. Targa’s estimated 2019
net growth capital expenditures continues to be approximately $2.4
billion. Based on current assumptions, Targa’s preliminary outlook
for 2020 net growth capital expenditures is approximately $1.2 to
$1.3 billion. The timing of moving forward with new Permian gas
processing plants and fractionation Train 9 in Mont Belvieu is
predicated on the Company’s outlook for estimated volume growth and
activity levels, which would impact whether the Company is at the
lower or higher end of its estimated net growth capital range as a
result of the timing of capital spend.
Asset Sales
Targa continues to evaluate and execute asset
sales to reduce leverage and focus on its core operations. During
the third quarter of 2019, the Company closed on the sale of an
equity-method investment for $70.3 million.
The Company has also engaged Jefferies LLC to
evaluate the potential divestiture of its Permian crude gathering
business, which includes crude gathering and storage assets in both
the Permian Midland and Permian Delaware. The potential divestiture
is predicated on third party valuations adequately capturing
Targa's forward growth expectations for the assets, and no
assurance can be made that a sale will be consummated.
Conference Call
The Company will host a conference call for the
investment community at 11:00 a.m. Eastern time (10:00 a.m. Central
time) on November 7, 2019 to discuss third 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/ih4at2qd or by dialing
877-881-2598. The conference ID number for the dial-in is 4349515.
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
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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2019 |
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2018 |
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2019 vs. 2018 |
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2019 |
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2018 |
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2019 vs. 2018 |
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(In millions) |
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Revenues: |
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Sales of commodities |
$ |
1,594.2 |
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|
$ |
2,654.1 |
|
|
$ |
(1,059.9 |
) |
|
|
(40 |
%) |
|
$ |
5,254.8 |
|
|
$ |
6,981.4 |
|
|
$ |
(1,726.6 |
) |
|
|
(25 |
%) |
Fees from midstream services |
|
308.3 |
|
|
|
332.3 |
|
|
|
(24.0 |
) |
|
|
(7 |
%) |
|
|
942.4 |
|
|
|
904.9 |
|
|
|
37.5 |
|
|
|
4 |
% |
Total revenues |
|
1,902.5 |
|
|
|
2,986.4 |
|
|
|
(1,083.9 |
) |
|
|
(36 |
%) |
|
|
6,197.2 |
|
|
|
7,886.3 |
|
|
|
(1,689.1 |
) |
|
|
(21 |
%) |
Product purchases |
|
1,328.1 |
|
|
|
2,383.5 |
|
|
|
(1,055.4 |
) |
|
|
(44 |
%) |
|
|
4,415.7 |
|
|
|
6,229.7 |
|
|
|
(1,814.0 |
) |
|
|
(29 |
%) |
Gross margin (1) |
|
574.4 |
|
|
|
602.9 |
|
|
|
(28.5 |
) |
|
|
(5 |
%) |
|
|
1,781.5 |
|
|
|
1,656.6 |
|
|
|
124.9 |
|
|
|
8 |
% |
Operating expenses |
|
200.2 |
|
|
|
194.9 |
|
|
|
5.3 |
|
|
|
3 |
% |
|
|
600.8 |
|
|
|
538.7 |
|
|
|
62.1 |
|
|
|
12 |
% |
Operating margin (1) |
|
374.2 |
|
|
|
408.0 |
|
|
|
(33.8 |
) |
|
|
(8 |
%) |
|
|
1,180.7 |
|
|
|
1,117.9 |
|
|
|
62.8 |
|
|
|
6 |
% |
Depreciation and amortization
expense |
|
244.3 |
|
|
|
206.3 |
|
|
|
38.0 |
|
|
|
18 |
% |
|
|
718.9 |
|
|
|
607.1 |
|
|
|
111.8 |
|
|
|
18 |
% |
General and administrative
expense |
|
69.9 |
|
|
|
63.2 |
|
|
|
6.7 |
|
|
|
11 |
% |
|
|
223.5 |
|
|
|
176.9 |
|
|
|
46.6 |
|
|
|
26 |
% |
Other operating (income)
expense |
|
18.4 |
|
|
|
61.8 |
|
|
|
(43.4 |
) |
|
|
(70 |
%) |
|
|
21.7 |
|
|
|
15.7 |
|
|
|
6.0 |
|
|
|
38 |
% |
Income (loss) from
operations |
|
41.6 |
|
|
|
76.7 |
|
|
|
(35.1 |
) |
|
|
(46 |
%) |
|
|
216.6 |
|
|
|
318.2 |
|
|
|
(101.6 |
) |
|
|
(32 |
%) |
Interest expense, net |
|
(89.1 |
) |
|
|
(78.2 |
) |
|
|
(10.9 |
) |
|
|
(14 |
%) |
|
|
(241.8 |
) |
|
|
(124.2 |
) |
|
|
(117.6 |
) |
|
|
(95 |
%) |
Equity earnings (loss) |
|
10.0 |
|
|
|
3.0 |
|
|
|
7.0 |
|
|
|
233 |
% |
|
|
15.9 |
|
|
|
6.4 |
|
|
|
9.5 |
|
|
|
148 |
% |
Gain (loss) from financing
activities |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(1.4 |
) |
|
|
(2.0 |
) |
|
|
0.6 |
|
|
|
30 |
% |
Gain (loss) from sale of
equity-method investment |
|
65.8 |
|
|
|
— |
|
|
|
65.8 |
|
|
|
— |
|
|
|
65.8 |
|
|
|
— |
|
|
|
65.8 |
|
|
|
— |
|
Change in contingent
considerations |
|
— |
|
|
|
(16.6 |
) |
|
|
16.6 |
|
|
|
100 |
% |
|
|
(8.8 |
) |
|
|
(12.1 |
) |
|
|
3.3 |
|
|
|
27 |
% |
Income tax (expense)
benefit |
|
3.8 |
|
|
|
3.9 |
|
|
|
(0.1 |
) |
|
|
(3 |
%) |
|
|
10.0 |
|
|
|
(37.7 |
) |
|
|
47.7 |
|
|
|
127 |
% |
Net income (loss) |
|
32.1 |
|
|
|
(11.2 |
) |
|
|
43.3 |
|
|
NM |
|
|
|
56.3 |
|
|
|
148.6 |
|
|
|
(92.3 |
) |
|
|
(62 |
%) |
Less: Net income (loss)
attributable to noncontrolling interests |
|
79.4 |
|
|
|
12.5 |
|
|
|
66.9 |
|
|
NM |
|
|
|
152.7 |
|
|
|
40.4 |
|
|
|
112.3 |
|
|
|
278 |
% |
Net income (loss) attributable
to Targa Resources Corp. |
|
(47.3 |
) |
|
|
(23.7 |
) |
|
|
(23.6 |
) |
|
|
(100 |
%) |
|
|
(96.4 |
) |
|
|
108.2 |
|
|
|
(204.6 |
) |
|
|
(189 |
%) |
Dividends on Series A
Preferred Stock |
|
22.9 |
|
|
|
22.9 |
|
|
|
— |
|
|
|
— |
|
|
|
68.8 |
|
|
|
68.8 |
|
|
|
— |
|
|
|
— |
|
Deemed dividends on Series A
Preferred Stock |
|
8.4 |
|
|
|
7.4 |
|
|
|
1.0 |
|
|
|
14 |
% |
|
|
24.4 |
|
|
|
21.5 |
|
|
|
2.9 |
|
|
|
13 |
% |
Net income (loss) attributable to common shareholders |
$ |
(78.6 |
) |
|
$ |
(54.0 |
) |
|
$ |
(24.6 |
) |
|
|
(46 |
%) |
|
$ |
(189.6 |
) |
|
$ |
17.9 |
|
|
$ |
(207.5 |
) |
|
NM |
|
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
349.6 |
|
|
$ |
347.2 |
|
|
$ |
2.4 |
|
|
|
— |
|
|
$ |
970.3 |
|
|
$ |
958.3 |
|
|
$ |
12.0 |
|
|
|
1 |
% |
Distributable cash flow
(1) |
|
229.9 |
|
|
|
287.2 |
|
|
|
(57.3 |
) |
|
|
(20 |
%) |
|
|
619.4 |
|
|
|
728.5 |
|
|
|
(109.1 |
) |
|
|
(15 |
%) |
Growth capital expenditures
(2) |
|
511.3 |
|
|
|
984.4 |
|
|
|
(473.1 |
) |
|
|
(48 |
%) |
|
|
2,203.4 |
|
|
|
2,230.0 |
|
|
|
(26.6 |
) |
|
|
(1 |
%) |
Maintenance capital
expenditures (3) |
|
31.0 |
|
|
|
33.3 |
|
|
|
(2.3 |
) |
|
|
(7 |
%) |
|
|
101.5 |
|
|
|
80.4 |
|
|
|
21.1 |
|
|
|
26 |
% |
(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 $1,870.8
million and $1,824.0 million for the nine months ended September
30, 2019 and 2018. Net contributions to investments in
unconsolidated affiliates were $75.4 million and $99.9 million for
the nine months ended September 30, 2019 and 2018. |
(3) |
Maintenance capital expenditures,
net of contributions from noncontrolling interests, were $95.5
million and $78.8 million for the nine months ended September
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 September 30, 2019 Compared to Three Months
Ended September 30, 2018
The decrease in commodity sales reflects lower
NGL, natural gas, and condensate prices ($1,352.5 million), the
unfavorable impact of mark-to-market hedges ($102.0 million) and
lower petroleum products and condensate volumes ($62.2 million),
partially offset by higher NGL, crude marketing and natural gas
volumes ($373.3 million), the favorable impact of equity volume
hedges ($59.5 million) and higher crude marketing prices ($20.1
million).
The decrease in fees from midstream services is
largely due to lower gas gathering fees attributable to the
Company's non-cash take in-kind equity volumes, partially offset by
an overall increase in gas gathered volumes. Subsequent to the
Company's January 2018 adoption of ASC 606, Revenue from Contracts
with Customers, non-cash take in-kind volumes, which have exposure
to commodity prices, received from a customer are presented as
a component of fees from midstream services with a corresponding
offset to product purchases and have no impact to the Company's
operating margin or gross margin.
The decrease in product purchases reflects
decreased NGL, natural gas and condensate prices, partially offset
by increases in volumes.
Lower 2019 operating margin and gross margin
reflect decreased segment results for Gathering and Processing,
offset by increased segment results for Logistics and Marketing.
See “Review of Segment Performance” for additional information
regarding changes in operating margin and gross margin on a segment
basis. Operating margin and gross margin also include the effect of
hedges as discussed in “Review of Segment Performance – Other.”
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 Grand
Prix.
General and administrative expense increased
primarily due to higher compensation and benefits costs as a result
of increased staffing levels, partially offset by lower
professional services and lower contract labor.
During the third quarter of 2019, the Company
wrote down certain assets to their recoverable amounts. In the
prior year, a loss on sale was recognized associated with the
Company’s refined products and crude oil storage and terminaling
facilities in Tacoma, WA, and Baltimore, MD.
Interest expense, net, increased due to higher
average borrowings, partially offset by higher capitalized interest
related to the Company's major growth investments.
The increase in equity earnings is primarily due
to higher earnings from GCX.
During the third quarter of 2019, the Company
closed on the sale of an equity-method investment for
$70.3 million that resulted in the recognition of a gain of
$65.8 million.
During 2019, the Permian Acquisition contingent
consideration earn-out period ended and resulted in a final payment
in May. During 2018, the Company recorded an expense resulting
primarily from an increase in fair value of the contingent
consideration liability. The fair value change was primarily
attributable to a shorter discount period.
The change in income tax benefit is primarily
due to a lower annual effective tax rate and higher tax benefits
related to share-based awards that vested during the quarter.
Net income attributable to noncontrolling
interests was higher in 2019 due to earnings allocated to
noncontrolling interest holders in Targa Badlands, Grand Prix and
Train 6.
Nine Months Ended September 30, 2019 Compared to
Nine Months Ended September 30, 2018
The decrease in commodity sales reflects lower
commodity prices ($2,640.8 million) and lower petroleum products
volumes due to the sale of certain petroleum logistics storage and
terminaling facilities in the fourth quarter of 2018 ($85.3
million), partially offset by higher NGL, crude marketing and
natural gas volumes ($936.4 million) and the favorable impact of
hedges ($65.8 million). Higher exports and crude gathering fees
resulted in increased fees from midstream services.
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 Logistics and Marketing,
offset by decreased segment results for Gathering and Processing.
See “Review of Segment Performance” for additional information
regarding changes in operating margin and gross margin on a segment
basis. Operating margin and gross margin also include the effect of
hedges as discussed in “Review of Segment Performance – Other.”
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 Grand
Prix.
General and administrative expense increased
primarily due to higher compensation and benefits costs as a result
of increased staffing levels and higher system costs.
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.
The increase in equity earnings is primarily due
to higher earnings from GCX.
During 2019, the Company closed on the sale of
an equity-method investment for $70.3 million that resulted in
the recognition of a gain of $65.8 million.
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.
Net income attributable to noncontrolling
interests was higher in 2019 due to earnings allocated to
noncontrolling interest holders in Targa Badlands, Grand Prix and
Train 6.
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 September 30, |
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
2019 |
|
|
2018 |
|
|
|
2019 vs. 2018 |
|
Gross margin |
$ |
|
328.8 |
|
|
$ |
|
373.7 |
|
|
$ |
|
(44.9 |
) |
|
|
(12 |
%) |
|
$ |
|
1,006.1 |
|
|
$ |
|
1,046.3 |
|
|
$ |
|
(40.2 |
) |
|
|
(4 |
%) |
Operating expenses |
|
|
120.2 |
|
|
|
|
118.4 |
|
|
|
|
1.8 |
|
|
|
2 |
% |
|
|
|
375.2 |
|
|
|
|
327.9 |
|
|
|
|
47.3 |
|
|
|
14 |
% |
Operating margin |
$ |
|
208.6 |
|
|
$ |
|
255.3 |
|
|
$ |
|
(46.7 |
) |
|
|
(18 |
%) |
|
$ |
|
630.9 |
|
|
$ |
|
718.4 |
|
|
$ |
|
(87.5 |
) |
|
|
(12 |
%) |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
1,546.7 |
|
|
|
|
1,161.7 |
|
|
|
|
385.0 |
|
|
|
33 |
% |
|
|
|
1,438.7 |
|
|
|
|
1,100.8 |
|
|
|
|
337.9 |
|
|
|
31 |
% |
Permian Delaware |
|
|
629.4 |
|
|
|
|
470.5 |
|
|
|
|
158.9 |
|
|
|
34 |
% |
|
|
|
552.2 |
|
|
|
|
432.5 |
|
|
|
|
119.7 |
|
|
|
28 |
% |
Total Permian |
|
|
2,176.1 |
|
|
|
|
1,632.2 |
|
|
|
|
543.9 |
|
|
|
|
|
|
|
|
1,990.9 |
|
|
|
|
1,533.3 |
|
|
|
|
457.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
328.6 |
|
|
|
|
364.1 |
|
|
|
|
(35.5 |
) |
|
|
(10 |
%) |
|
|
|
335.3 |
|
|
|
|
397.8 |
|
|
|
|
(62.5 |
) |
|
|
(16 |
%) |
North Texas |
|
|
228.2 |
|
|
|
|
247.6 |
|
|
|
|
(19.4 |
) |
|
|
(8 |
%) |
|
|
|
227.6 |
|
|
|
|
243.0 |
|
|
|
|
(15.4 |
) |
|
|
(6 |
%) |
SouthOK (6) |
|
|
590.8 |
|
|
|
|
568.2 |
|
|
|
|
22.6 |
|
|
|
4 |
% |
|
|
|
606.1 |
|
|
|
|
549.4 |
|
|
|
|
56.7 |
|
|
|
10 |
% |
WestOK |
|
|
329.2 |
|
|
|
|
353.9 |
|
|
|
|
(24.7 |
) |
|
|
(7 |
%) |
|
|
|
335.2 |
|
|
|
|
350.8 |
|
|
|
|
(15.6 |
) |
|
|
(4 |
%) |
Total Central |
|
|
1,476.8 |
|
|
|
|
1,533.8 |
|
|
|
|
(57.0 |
) |
|
|
|
|
|
|
|
1,504.2 |
|
|
|
|
1,541.0 |
|
|
|
|
(36.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (7), (8) |
|
|
120.8 |
|
|
|
|
90.5 |
|
|
|
|
30.3 |
|
|
|
33 |
% |
|
|
|
103.4 |
|
|
|
|
83.3 |
|
|
|
|
20.1 |
|
|
|
24 |
% |
Total Field |
|
|
3,773.7 |
|
|
|
|
3,256.5 |
|
|
|
|
517.2 |
|
|
|
|
|
|
|
|
3,598.5 |
|
|
|
|
3,157.6 |
|
|
|
|
440.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
721.0 |
|
|
|
|
783.3 |
|
|
|
|
(62.3 |
) |
|
|
(8 |
%) |
|
|
|
765.1 |
|
|
|
|
724.5 |
|
|
|
|
40.6 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,494.7 |
|
|
|
|
4,039.8 |
|
|
|
|
454.9 |
|
|
|
11 |
% |
|
|
|
4,363.6 |
|
|
|
|
3,882.1 |
|
|
|
|
481.5 |
|
|
|
12 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
216.5 |
|
|
|
|
152.2 |
|
|
|
|
64.3 |
|
|
|
42 |
% |
|
|
|
199.8 |
|
|
|
|
148.0 |
|
|
|
|
51.8 |
|
|
|
35 |
% |
Permian Delaware |
|
|
82.3 |
|
|
|
|
58.9 |
|
|
|
|
23.4 |
|
|
|
40 |
% |
|
|
|
71.4 |
|
|
|
|
51.6 |
|
|
|
|
19.8 |
|
|
|
38 |
% |
Total Permian |
|
|
298.8 |
|
|
|
|
211.1 |
|
|
|
|
87.7 |
|
|
|
|
|
|
|
|
271.2 |
|
|
|
|
199.6 |
|
|
|
|
71.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
41.5 |
|
|
|
|
49.0 |
|
|
|
|
(7.5 |
) |
|
|
(15 |
%) |
|
|
|
44.0 |
|
|
|
|
52.5 |
|
|
|
|
(8.5 |
) |
|
|
(16 |
%) |
North Texas |
|
|
27.3 |
|
|
|
|
29.6 |
|
|
|
|
(2.3 |
) |
|
|
(8 |
%) |
|
|
|
26.9 |
|
|
|
|
28.1 |
|
|
|
|
(1.2 |
) |
|
|
(4 |
%) |
SouthOK (6) |
|
|
69.5 |
|
|
|
|
61.2 |
|
|
|
|
8.3 |
|
|
|
14 |
% |
|
|
|
65.4 |
|
|
|
|
53.8 |
|
|
|
|
11.6 |
|
|
|
22 |
% |
WestOK |
|
|
19.2 |
|
|
|
|
20.7 |
|
|
|
|
(1.5 |
) |
|
|
(7 |
%) |
|
|
|
22.4 |
|
|
|
|
19.9 |
|
|
|
|
2.5 |
|
|
|
13 |
% |
Total Central |
|
|
157.5 |
|
|
|
|
160.5 |
|
|
|
|
(3.0 |
) |
|
|
|
|
|
|
|
158.7 |
|
|
|
|
154.3 |
|
|
|
|
4.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (8) |
|
|
14.0 |
|
|
|
|
10.5 |
|
|
|
|
3.5 |
|
|
|
33 |
% |
|
|
|
12.2 |
|
|
|
|
10.5 |
|
|
|
|
1.7 |
|
|
|
16 |
% |
Total Field |
|
|
470.3 |
|
|
|
|
382.1 |
|
|
|
|
88.2 |
|
|
|
|
|
|
|
|
442.1 |
|
|
|
|
364.4 |
|
|
|
|
77.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
45.4 |
|
|
|
|
47.3 |
|
|
|
|
(1.9 |
) |
|
|
(4 |
%) |
|
|
|
47.0 |
|
|
|
|
42.8 |
|
|
|
|
4.2 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
515.7 |
|
|
|
|
429.4 |
|
|
|
|
86.3 |
|
|
|
20 |
% |
|
|
|
489.1 |
|
|
|
|
407.2 |
|
|
|
|
81.9 |
|
|
|
20 |
% |
Crude oil gathered, Badlands,
MBbl/d |
|
|
164.3 |
|
|
|
|
161.7 |
|
|
|
|
2.6 |
|
|
|
2 |
% |
|
|
|
167.0 |
|
|
|
|
139.9 |
|
|
|
|
27.1 |
|
|
|
19 |
% |
Crude oil gathered, Permian,
MBbl/d |
|
|
95.2 |
|
|
|
|
75.1 |
|
|
|
|
20.1 |
|
|
|
27 |
% |
|
|
|
86.1 |
|
|
|
|
63.8 |
|
|
|
|
22.3 |
|
|
|
35 |
% |
Natural gas sales, BBtu/d
(3) |
|
|
2,056.6 |
|
|
|
|
1,817.6 |
|
|
|
|
239.0 |
|
|
|
13 |
% |
|
|
|
2,011.2 |
|
|
|
|
1,821.1 |
|
|
|
|
190.1 |
|
|
|
10 |
% |
NGL sales, MBbl/d |
|
|
398.0 |
|
|
|
|
329.6 |
|
|
|
|
68.4 |
|
|
|
21 |
% |
|
|
|
382.4 |
|
|
|
|
311.3 |
|
|
|
|
71.1 |
|
|
|
23 |
% |
Condensate sales, MBbl/d |
|
|
11.0 |
|
|
|
|
12.6 |
|
|
|
|
(1.6 |
) |
|
|
(13 |
%) |
|
|
|
12.2 |
|
|
|
|
12.8 |
|
|
|
|
(0.6 |
) |
|
|
(5 |
%) |
Average realized
prices (9): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
1.02 |
|
|
|
|
1.93 |
|
|
|
|
(0.91 |
) |
|
|
(47 |
%) |
|
|
|
1.19 |
|
|
|
|
2.03 |
|
|
|
|
(0.84 |
) |
|
|
(41 |
%) |
NGL, $/gal |
|
|
0.27 |
|
|
|
|
0.75 |
|
|
|
|
(0.48 |
) |
|
|
(64 |
%) |
|
|
|
0.35 |
|
|
|
|
0.67 |
|
|
|
|
(0.32 |
) |
|
|
(48 |
%) |
Condensate, $/Bbl |
|
|
50.94 |
|
|
|
|
58.31 |
|
|
|
|
(7.37 |
) |
|
|
(13 |
%) |
|
|
|
49.79 |
|
|
|
|
58.49 |
|
|
|
|
(8.70 |
) |
|
|
(15 |
%) |
(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 September 30, 2019 Compared
to Three Months Ended September 30, 2018
The decrease in gross margin was primarily due
to lower commodity prices, partially offset by higher Permian and
Badlands volumes. The impact of lower commodity prices in 2019
excludes the third quarter realized gain from the Company's hedging
activities presented in Other. NGL production, NGL sales and
natural gas sales increased primarily due to higher inlet volumes
and increased NGL recoveries. In the Permian, natural gas gathered
volumes and NGL production increased due to incremental processing
capacity available with the commencement of operations at the
Johnson Plant in the fourth quarter of 2018, the Hopson Plant in
the second quarter of 2019 and the Pembrook Plant in the third
quarter of 2019, while total crude oil gathered volumes increased
due to production from new wells. In the Badlands, natural gas
gathered volumes and NGL production increased due to incremental
processing capacity available with the commencement of operations
at the Little Missouri 4 Plant in the third quarter of 2019, while
total crude oil gathered volumes increased due to production from
new wells.
Operating expenses were relatively flat with
increased operating expenses in the Permian, due to gas plant and
system expansions, partially offset by reductions in other
regions.
Nine Months Ended September 30, 2019 Compared to
Nine Months Ended September 30, 2018
The decrease in gross margin was primarily due
to lower commodity prices, partially offset by higher Permian and
Badlands volumes. The impact of lower commodity prices in 2019
excludes the realized gain from the Company's hedging activities
presented in Other. NGL production, NGL sales and natural gas sales
increased primarily due to higher inlet volumes and increased NGL
recoveries. In the Permian, natural gas gathered volumes and NGL
production increased due to incremental processing capacity
available with the commencement of operations at the Johnson Plant
in the fourth quarter of 2018, the Hopson Plant in the second
quarter of 2019 and the Pembrook Plant in the third quarter of
2019. In the Badlands, natural gas gathered volumes and NGL
production increased due to production from new wells and the
incremental processing capacity available with the commencement of
operations at the Little Missouri 4 Plant in the third quarter of
2019. Total crude oil gathered volumes increased in both the
Permian region and the Badlands due to production from new
wells.
The increase in operating expenses was primarily
driven by gas plant and system expansions in the Permian region and
the Badlands. Operating expenses in other areas were relatively
flat.
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 September 30, |
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
(In millions) |
|
Gross margin |
|
$ |
|
310.4 |
|
|
$ |
|
249.4 |
|
|
$ |
|
61.0 |
|
|
|
24 |
% |
|
$ |
|
792.4 |
|
|
$ |
|
653.1 |
|
|
$ |
|
139.3 |
|
|
|
21 |
% |
Operating expenses |
|
|
|
81.5 |
|
|
|
|
75.9 |
|
|
|
|
5.6 |
|
|
|
7 |
% |
|
|
|
227.4 |
|
|
|
|
211.4 |
|
|
|
|
16.0 |
|
|
|
8 |
% |
Operating margin |
|
$ |
|
228.9 |
|
|
$ |
|
173.5 |
|
|
$ |
|
55.4 |
|
|
|
32 |
% |
|
$ |
|
565.0 |
|
|
$ |
|
441.7 |
|
|
$ |
|
123.3 |
|
|
|
28 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (2) |
|
|
|
508.8 |
|
|
|
|
454.5 |
|
|
|
|
54.3 |
|
|
|
12 |
% |
|
|
|
492.8 |
|
|
|
|
419.0 |
|
|
|
|
73.8 |
|
|
|
18 |
% |
Export volumes (3) |
|
|
|
239.2 |
|
|
|
|
208.2 |
|
|
|
|
31.0 |
|
|
|
15 |
% |
|
|
|
228.1 |
|
|
|
|
200.2 |
|
|
|
|
27.9 |
|
|
|
14 |
% |
Pipeline throughput (4) |
|
|
|
131.8 |
|
|
|
|
- |
|
|
|
|
131.8 |
|
|
|
- |
|
|
|
|
44.4 |
|
|
|
|
- |
|
|
|
|
44.4 |
|
|
|
- |
|
NGL sales |
|
|
|
672.1 |
|
|
|
|
555.7 |
|
|
|
|
116.4 |
|
|
|
21 |
% |
|
|
|
620.9 |
|
|
|
|
526.7 |
|
|
|
|
94.2 |
|
|
|
18 |
% |
Average realized
prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL realized price, $/gal |
|
$ |
|
0.43 |
|
|
$ |
|
0.88 |
|
|
$ |
|
(0.45 |
) |
|
|
(51 |
%) |
|
$ |
|
0.50 |
|
|
$ |
|
0.80 |
|
|
$ |
|
(0.30 |
) |
|
|
(38 |
%) |
(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. |
(4) |
Pipeline throughput represents the total quantity of mixed NGLs
delivered by Grand Prix to Mont Belvieu. |
Three Months Ended September 30, 2019 Compared to Three Months
Ended September 30, 2018
Logistics and Marketing gross margin increased
due to higher NGL transportation, fractionation and services
margin, higher marketing margin, and higher LPG export margin,
partially offset by lower terminaling and storage throughput. NGL
transportation, fractionation and services margin increased due to
volumes delivered on Grand Prix, which began full service into Mont
Belvieu during the third quarter of 2019, and higher fractionation
volumes as a result of the commencement of operations of Train 6 in
the second quarter of 2019. Fractionation and services margin was
unfavorably impacted by fewer short-term high fee fractionation
contracts in the third quarter of 2019 compared to the same period
last year, and by a planned maintenance turnaround of the Company's
Cedar Bayou fractionator. Marketing margin increased due to
optimization of gas and liquids arrangements. LPG export margin
increased due to higher volumes. 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
maintenance, higher fuel and power costs that are largely passed
through to customers, and higher compensation and benefits
primarily attributable to Grand Prix and Train 6 operations,
partially offset by the sale of certain petroleum logistics
terminals in the fourth quarter of 2018.
Nine Months Ended September 30, 2019 Compared to
Nine Months Ended September 30, 2018
Logistics and Marketing gross margin increased
due to higher NGL transportation, fractionation and services
margin, higher LPG export margin, and higher marketing margin,
partially offset by lower terminaling and storage throughput. NGL
transportation, fractionation and services margin increased due to
volumes delivered on Grand Prix, which began full service into Mont
Belvieu during the third quarter of 2019, and higher fractionation
volumes as a result of the commencement of operations of Train 6 in
the second quarter of 2019. Fractionation and services margin was
unfavorably impacted by fewer short-term high fee fractionation
contracts in the third quarter of 2019 compared to the same period
last year, and by a planned maintenance turnaround of the Company's
Cedar Bayou fractionator. LPG export margin increased due to higher
volumes. Marketing margin increased due to optimization of gas and
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 fuel
and power costs that are largely passed through to customers,
higher maintenance, and higher compensation and benefits and higher
taxes primarily attributable to Grand Prix and Train 6 operations,
partially offset by the sale of certain petroleum logistics
terminals in the fourth quarter of 2018.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
2019 |
|
|
2018 |
|
|
2019 vs. 2018 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Gross margin |
|
$ |
(63.3 |
) |
|
$ |
(20.8 |
) |
|
$ |
(42.5 |
) |
|
$ |
(15.2 |
) |
|
$ |
(42.2 |
) |
|
$ |
27.0 |
|
Operating margin |
|
$ |
(63.3 |
) |
|
$ |
(20.8 |
) |
|
$ |
(42.5 |
) |
|
$ |
(15.2 |
) |
|
$ |
(42.2 |
) |
|
$ |
27.0 |
|
Other contains the results of commodity
derivative activities related to Gathering and Processing hedges of
equity volumes that are included in operating margin. 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 Company has also entered into swaps and
basis swaps that do not qualify for hedge accounting treatment. The
mark-to-market gains/losses related to these derivative instruments
represent unrealized, non-cash changes in the fair value of the
instruments. For the three and nine months ended September 30,
2019, the unrealized mark-to-market losses are primarily
attributable to unfavorable movements in natural gas forward basis
prices and will be more than offset by locked-in gains to be
realized in future periods from the underlying transportation
arrangements.
The following table provides a breakdown of the change in Other
operating margin:
|
|
Three Months Ended September 30, 2019 |
|
|
Three Months Ended September 30, 2018 |
|
|
|
|
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
18.8 |
|
|
$ |
1.07 |
|
|
$ |
20.1 |
|
|
|
15.7 |
|
|
$ |
0.82 |
|
|
$ |
12.9 |
|
NGL (MMgal) |
|
|
110.0 |
|
|
|
0.17 |
|
|
|
18.5 |
|
|
|
99.0 |
|
|
|
(0.27 |
) |
|
|
(26.4 |
) |
Crude oil (MBbl) |
|
|
0.4 |
|
|
|
(1.76 |
) |
|
|
(0.7 |
) |
|
|
0.5 |
|
|
|
(15.81 |
) |
|
|
(8.1 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
|
|
|
(101.2 |
) |
|
|
|
|
|
|
|
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
|
|
$ |
(63.3 |
) |
|
|
|
|
|
|
|
|
|
$ |
(20.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019 |
|
|
Nine Months Ended September 30, 2018 |
|
|
|
|
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
47.0 |
|
|
$ |
1.29 |
|
|
$ |
60.6 |
|
|
|
48.6 |
|
|
$ |
0.74 |
|
|
$ |
35.8 |
|
NGL (MMgal) |
|
|
252.1 |
|
|
|
0.11 |
|
|
|
27.9 |
|
|
|
286.3 |
|
|
|
(0.17 |
) |
|
|
(49.7 |
) |
Crude oil (MBbl) |
|
|
1.1 |
|
|
|
(2.28 |
) |
|
|
(2.6 |
) |
|
|
1.5 |
|
|
|
(13.10 |
) |
|
|
(20.0 |
) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
|
|
|
(101.1 |
) |
|
|
|
|
|
|
|
|
|
|
(8.3 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
(15.2 |
) |
|
|
|
|
|
|
|
|
|
$ |
(42.2 |
) |
(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 attributable to TRC to Adjusted EBITDA and Distributable
Cash Flow for the periods indicated:
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 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 |
|
$ |
|
(47.3 |
) |
|
$ |
|
(23.7 |
) |
|
$ |
|
(96.4 |
) |
|
$ |
|
108.2 |
|
Income attributable to TRP preferred limited partners |
|
|
|
2.8 |
|
|
|
|
2.8 |
|
|
|
|
8.4 |
|
|
|
|
8.4 |
|
Interest (income) expense, net (1) |
|
|
|
89.1 |
|
|
|
|
78.2 |
|
|
|
|
241.8 |
|
|
|
|
124.2 |
|
Income tax expense (benefit) |
|
|
|
(3.8 |
) |
|
|
|
(3.9 |
) |
|
|
|
(10.0 |
) |
|
|
|
37.7 |
|
Depreciation and amortization expense |
|
|
|
244.3 |
|
|
|
|
206.3 |
|
|
|
|
718.9 |
|
|
|
|
607.1 |
|
(Gain) loss on sale or disposition of assets |
|
|
|
0.5 |
|
|
|
|
61.1 |
|
|
|
|
3.6 |
|
|
|
|
14.3 |
|
Write-down of assets |
|
|
|
17.9 |
|
|
|
|
— |
|
|
|
|
17.9 |
|
|
|
|
— |
|
(Gain) loss from sale of equity-method investment |
|
|
|
(65.8 |
) |
|
|
|
— |
|
|
|
|
(65.8 |
) |
|
|
|
— |
|
(Gain) loss from financing activities (2) |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
1.4 |
|
|
|
|
2.0 |
|
Equity (earnings) loss |
|
|
|
(10.0 |
) |
|
|
|
(3.0 |
) |
|
|
|
(15.9 |
) |
|
|
|
(6.4 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
|
|
14.0 |
|
|
|
|
7.5 |
|
|
|
|
33.4 |
|
|
|
|
21.4 |
|
Change in contingent considerations |
|
|
|
— |
|
|
|
|
16.6 |
|
|
|
|
8.8 |
|
|
|
|
12.1 |
|
Compensation on equity grants |
|
|
|
16.1 |
|
|
|
|
13.8 |
|
|
|
|
49.0 |
|
|
|
|
40.7 |
|
Risk management activities |
|
|
|
100.7 |
|
|
|
|
(0.8 |
) |
|
|
|
100.8 |
|
|
|
|
8.3 |
|
Noncontrolling interests adjustments (3) |
|
|
|
(8.9 |
) |
|
|
|
(7.7 |
) |
|
|
|
(25.6 |
) |
|
|
|
(19.7 |
) |
TRC Adjusted EBITDA (4) |
|
$ |
|
349.6 |
|
|
$ |
|
347.2 |
|
|
$ |
|
970.3 |
|
|
$ |
|
958.3 |
|
Distributions to TRP preferred limited partners |
|
|
|
(2.8 |
) |
|
|
|
(2.8 |
) |
|
|
|
(8.4 |
) |
|
|
|
(8.4 |
) |
Splitter Agreement (5) |
|
|
|
— |
|
|
|
|
43.1 |
|
|
|
|
— |
|
|
|
|
43.1 |
|
Interest expense on debt obligations (6) |
|
|
|
(88.0 |
) |
|
|
|
(67.5 |
) |
|
|
|
(247.0 |
) |
|
|
|
(185.7 |
) |
Maintenance capital expenditures |
|
|
|
(31.0 |
) |
|
|
|
(33.3 |
) |
|
|
|
(101.5 |
) |
|
|
|
(80.4 |
) |
Noncontrolling interests adjustments of maintenance capital
expenditures |
|
|
|
2.1 |
|
|
|
|
0.5 |
|
|
|
|
6.0 |
|
|
|
|
1.6 |
|
Distributable Cash
Flow |
|
$ |
|
229.9 |
|
|
$ |
|
287.2 |
|
|
$ |
|
619.4 |
|
|
$ |
|
728.5 |
|
(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 $32.3 million for the three and nine months ended
September 30, 2018. There was no impact to Distributable Cash
Flow. |
(5) |
In Distributable Cash Flow,
Splitter Agreement represents the annual cash payment in the period
received. |
(6) |
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 September 30, |
|
|
Nine Months Ended September 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 |
|
$ |
|
(47.3 |
) |
|
$ |
|
(23.7 |
) |
|
$ |
|
(96.4 |
) |
|
$ |
|
108.2 |
|
Net income (loss) attributable
to noncontrolling interests |
|
|
|
79.4 |
|
|
|
|
12.5 |
|
|
|
|
152.7 |
|
|
|
|
40.4 |
|
Net income (loss) |
|
|
|
32.1 |
|
|
|
|
(11.2 |
) |
|
|
|
56.3 |
|
|
|
|
148.6 |
|
Depreciation and amortization expense |
|
|
|
244.3 |
|
|
|
|
206.3 |
|
|
|
|
718.9 |
|
|
|
|
607.1 |
|
General and administrative expense |
|
|
|
69.9 |
|
|
|
|
63.2 |
|
|
|
|
223.5 |
|
|
|
|
176.9 |
|
Interest (income) expense, net |
|
|
|
89.1 |
|
|
|
|
78.2 |
|
|
|
|
241.8 |
|
|
|
|
124.2 |
|
Income tax expense (benefit) |
|
|
|
(3.8 |
) |
|
|
|
(3.9 |
) |
|
|
|
(10.0 |
) |
|
|
|
37.7 |
|
(Gain) loss on sale or disposition of assets |
|
|
|
0.5 |
|
|
|
|
61.1 |
|
|
|
|
3.6 |
|
|
|
|
14.3 |
|
Write-down of assets |
|
|
|
17.9 |
|
|
|
|
— |
|
|
|
|
17.9 |
|
|
|
|
— |
|
(Gain) loss from sale of equity-method investment |
|
|
|
(65.8 |
) |
|
|
|
— |
|
|
|
|
(65.8 |
) |
|
|
|
— |
|
(Gain) loss from financing activities |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
1.4 |
|
|
|
|
2.0 |
|
Change in contingent considerations |
|
|
|
— |
|
|
|
|
16.6 |
|
|
|
|
8.8 |
|
|
|
|
12.1 |
|
Other, net |
|
|
|
(10.0 |
) |
|
|
|
(2.3 |
) |
|
|
|
(15.7 |
) |
|
|
|
(5.0 |
) |
Operating margin |
|
|
|
374.2 |
|
|
|
|
408.0 |
|
|
|
|
1,180.7 |
|
|
|
|
1,117.9 |
|
Operating expenses |
|
|
|
200.2 |
|
|
|
|
194.9 |
|
|
|
|
600.8 |
|
|
|
|
538.7 |
|
Gross
margin |
|
$ |
|
574.4 |
|
|
$ |
|
602.9 |
|
|
$ |
|
1,781.5 |
|
|
$ |
|
1,656.6 |
|
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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