Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported third quarter 2024 results.
Third quarter 2024 net income attributable to
Targa Resources Corp. was $387.4 million compared to $220.0 million
for the third quarter of 2023. The Company reported adjusted
earnings before interest, income taxes, depreciation and
amortization, and other non-cash items (“adjusted EBITDA”)(1) of
$1,069.7 million for the third quarter of 2024 compared to $840.2
million for the third quarter of 2023.
Highlights
- Record adjusted EBITDA for the third quarter of $1.07
billion
- Record Permian, NGL transportation, and fractionation volumes
during the third quarter
- Completed its Daytona NGL Pipeline expansion during the third
quarter
- Repurchased approximately $168 million of common stock during
the third quarter, and $647 million for the nine months ended
September 30, 2024 at a weighted average price of $121.50
- Estimate full year 2024 adjusted EBITDA to be above the top end
of $3.95 billion to $4.05 billion range
- In August and October, upgraded by Fitch to BBB and by Moody’s
to Baa2
- In October, commenced operations at its new 275 million cubic
feet per day (“MMcf/d”) Greenwood II plant in Permian Midland and
its new 120 thousand barrels per day (“MBbl/d”) Train 10
fractionator in Mont Belvieu
- Announced two new 275 MMcf/d gas plants in the Permian
- Expect to recommend to Targa’s Board of Directors an annual
common dividend per share of $4.00 in 2025, a 33% increase to
2024
On October 10, 2024, the Company declared a
quarterly cash dividend of $0.75 per common share, or $3.00 per
common share on an annualized basis, for the third quarter of 2024.
Total cash dividends of approximately $164 million will be paid on
November 15, 2024 on all outstanding shares of common stock to
holders of record as of the close of business on October 31,
2024.
Targa repurchased 1,150,107 shares of its common
stock during the third quarter of 2024 at a weighted average per
share price of $146.02 for a total net cost of $167.9 million. As
of September 30, 2024, there was $1.1 billion remaining under the
Company’s Share Repurchase Programs.
Third Quarter 2024 - Sequential Quarter
over Quarter Commentary
Targa reported record third quarter adjusted
EBITDA of $1,069.7 million, representing a 9 percent increase
compared to the second quarter of 2024. The sequential increase in
adjusted EBITDA was attributable to higher volumes across Targa’s
Gathering and Processing (“G&P”) and Logistics and
Transportation (“L&T”) systems. In the G&P segment, higher
sequential adjusted operating margin was attributable to record
Permian natural gas inlet volumes, higher Badlands crude volumes,
and higher fees. In the L&T segment, record NGL pipeline
transportation and fractionation volumes, higher marketing margin
and higher LPG export volumes drove the sequential increase in
segment adjusted operating margin. Increasing NGL pipeline
transportation and fractionation volumes were attributable to
higher supply volumes from Targa’s Permian G&P systems and the
start-up of Targa’s Daytona NGL Pipeline. Marketing margin
increased due to greater optimization opportunities and higher LPG
export volumes benefited from improved market conditions. Higher
segment operating expenses were attributable to higher system
volumes and expansions.
Capitalization and
Liquidity
The Company’s total consolidated debt as of
September 30, 2024 was $14,254.7 million, net of $91.6 million
of debt issuance costs and $29.7 million of unamortized discount,
with $12,534.4 million of outstanding senior notes, $951.0 million
outstanding under the Commercial Paper Program, $600.0 million
outstanding under the Securitization Facility, and $290.6 million
of finance lease liabilities.
Total consolidated liquidity as of
September 30, 2024 was approximately $1.9 billion, including
$1.8 billion available under the TRGP Revolver and $127.2 million
of cash.
Financing Update
In August 2024, Targa completed an underwritten
public offering of $1.0 billion aggregate principal amount of its
5.500% Senior Notes due 2035 (the “5.500% Notes”), resulting in net
proceeds of approximately $990.1 million. Targa used the net
proceeds from the issuance to repay borrowings under the Commercial
Paper Program, a portion of which were incurred to repay the
remaining balance under the Term Loan Facility, and for general
corporate purposes.
In August 2024, the Partnership amended its
$600.0 million accounts receivable securitization facility (the
“Securitization Facility”) to extend the termination date of the
Securitization Facility to August 29, 2025.
In August 2024, Fitch Ratings Inc. (“Fitch”)
upgraded the Company’s corporate investment grade credit rating to
‘BBB’ from ‘BBB-’. In October 2024, Moody’s Ratings (“Moody’s”)
upgraded the Company’s corporate investment grade credit rating to
‘Baa2’ from ‘Baa3’.
Growth Projects Update
In the third quarter of 2024, Targa commenced
operations on its Daytona NGL Pipeline ahead of schedule and
under-budget. In October 2024, Targa commenced operations at its
new 275 MMcf/d Greenwood II plant in Permian Midland and its new
120 MBbl/d Train 10 fractionator in Mont Belvieu. Targa expects to
complete the reactivation of Gulf Coast Fractionators (“GCF”) in
Mont Belvieu in November 2024. In its G&P segment, construction
continues on Targa’s 275 MMcf/d Pembrook II and East Pembrook
plants in Permian Midland and its 275 MMcf/d Bull Moose and Bull
Moose II plants in Permian Delaware. In its L&T segment,
construction continues on Targa’s 150 MBbl/d Train 11 fractionator
in Mont Belvieu. Targa now expects to complete its East Pembrook
plant ahead of schedule in the second quarter of 2026 and remains
on-track to complete its other expansions as previously
disclosed.
In November 2024, in response to increasing
production and to meet the infrastructure needs of its customers,
Targa announced the construction of a new 275 MMcf/d cryogenic
natural gas processing plant in Permian Delaware (the “Falcon II
plant”) and a new 275 MMcf/d cryogenic natural gas processing plant
in Permian Midland (the “East Driver plant”). Falcon II and East
Driver are expected to commence operations in the second and third
quarters of 2026.
2024 and 2025 Outlook
Targa’s adjusted EBITDA and growth capital
projections are trending higher than previously estimated from the
acceleration of spending on infrastructure to handle additional
volume growth. The Company is in the middle of its planning
process, and consistent with previous years, Targa plans to detail
its full year 2025 operational and financial outlook in February
2025 in conjunction with its fourth quarter 2024 earnings
announcement. For 2024, the Company estimates full year adjusted
EBITDA to be above the top end of its $3.95 billion to $4.05
billion range. Targa continues to anticipate a meaningful
inflection in 2025 adjusted free cash flow generation relative to
2024.
Capital Allocation Update
For the first quarter of 2025, Management
intends to recommend to Targa’s Board of Directors an increase to
its common dividend to $1.00 per common share or $4.00 per common
share annualized. The recommended common dividend per share
increase, if approved, would be effective for the first quarter of
2025 and payable in May 2025. Beyond 2025, Targa expects to be in
position to continue to provide meaningful annual increases to its
common dividend. For the nine months ended September 30, 2024,
Targa has repurchased 5,322,367 shares of common stock at a
weighted average per share price of $121.50 for a total net cost of
$646.7 million. Targa expects to continue to be in position to
opportunistically repurchase its stock going forward with
approximately $1.1 billion remaining under its common Share
Repurchase Programs.
An earnings supplement presentation and updated
investor presentation are available under Events and Presentations
in the Investors section of the Company’s website at
www.targaresources.com/investors/events.
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 5, 2024 to discuss its third quarter results. The
conference call can be accessed via webcast under Events and
Presentations in the Investors section of the Company’s website at
www.targaresources.com/investors/events, or by going directly to
https://edge.media-server.com/mmc/p/yf8cw4hf/. A webcast replay
will be available at the link above approximately two hours after
the conclusion of the event.
(1) Adjusted EBITDA is a non-GAAP financial
measure and is discussed under “Non-GAAP Financial Measures.”
Targa Resources Corp. – Consolidated
Financial Results of Operations
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
3,217.0 |
|
|
$ |
3,374.3 |
|
|
$ |
(157.3 |
) |
|
|
(5 |
%) |
|
$ |
10,126.2 |
|
|
$ |
10,314.0 |
|
|
$ |
(187.8 |
) |
|
(2 |
%) |
Fees from midstream services |
|
634.8 |
|
|
|
522.3 |
|
|
|
112.5 |
|
|
|
22 |
% |
|
|
1,850.0 |
|
|
|
1,506.8 |
|
|
|
343.2 |
|
|
23 |
% |
Total revenues |
|
3,851.8 |
|
|
|
3,896.6 |
|
|
|
(44.8 |
) |
|
|
(1 |
%) |
|
|
11,976.2 |
|
|
|
11,820.8 |
|
|
|
155.4 |
|
|
1 |
% |
Product purchases and
fuel |
|
2,365.0 |
|
|
|
2,690.0 |
|
|
|
(325.0 |
) |
|
|
(12 |
%) |
|
|
7,780.4 |
|
|
|
7,777.9 |
|
|
|
2.5 |
|
|
— |
|
Operating expenses |
|
301.0 |
|
|
|
277.7 |
|
|
|
23.3 |
|
|
|
8 |
% |
|
|
869.7 |
|
|
|
808.4 |
|
|
|
61.3 |
|
|
8 |
% |
Depreciation and amortization
expense |
|
355.4 |
|
|
|
331.3 |
|
|
|
24.1 |
|
|
|
7 |
% |
|
|
1,044.5 |
|
|
|
988.2 |
|
|
|
56.3 |
|
|
6 |
% |
General and administrative
expense |
|
102.6 |
|
|
|
90.0 |
|
|
|
12.6 |
|
|
|
14 |
% |
|
|
287.4 |
|
|
|
253.4 |
|
|
|
34.0 |
|
|
13 |
% |
Other operating (income)
expense |
|
(0.4 |
) |
|
|
2.5 |
|
|
|
(2.9 |
) |
|
|
(116 |
%) |
|
|
(0.7 |
) |
|
|
2.0 |
|
|
|
(2.7 |
) |
|
(135 |
%) |
Income (loss) from
operations |
|
728.2 |
|
|
|
505.1 |
|
|
|
223.1 |
|
|
|
44 |
% |
|
|
1,994.9 |
|
|
|
1,990.9 |
|
|
|
4.0 |
|
|
— |
|
Interest expense, net |
|
(184.9 |
) |
|
|
(175.1 |
) |
|
|
(9.8 |
) |
|
|
6 |
% |
|
|
(589.5 |
) |
|
|
(509.8 |
) |
|
|
(79.7 |
) |
|
16 |
% |
Equity earnings (loss) |
|
2.2 |
|
|
|
3.0 |
|
|
|
(0.8 |
) |
|
|
(27 |
%) |
|
|
7.9 |
|
|
|
6.2 |
|
|
|
1.7 |
|
|
27 |
% |
Gain (loss) from financing
activities |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(0.8 |
) |
|
|
— |
|
|
|
(0.8 |
) |
|
(100 |
%) |
Other, net |
|
(0.4 |
) |
|
|
(0.1 |
) |
|
|
(0.3 |
) |
|
NM |
|
|
|
1.1 |
|
|
|
(4.9 |
) |
|
|
6.0 |
|
|
122 |
% |
Income tax (expense)
benefit |
|
(97.0 |
) |
|
|
(53.9 |
) |
|
|
(43.1 |
) |
|
|
80 |
% |
|
|
(274.1 |
) |
|
|
(260.7 |
) |
|
|
(13.4 |
) |
|
5 |
% |
Net income (loss) |
|
448.1 |
|
|
|
279.0 |
|
|
|
169.1 |
|
|
|
61 |
% |
|
|
1,139.5 |
|
|
|
1,221.7 |
|
|
|
(82.2 |
) |
|
(7 |
%) |
Less: Net income (loss)
attributable to noncontrolling interests |
|
60.7 |
|
|
|
59.0 |
|
|
|
1.7 |
|
|
|
3 |
% |
|
|
178.5 |
|
|
|
175.4 |
|
|
|
3.1 |
|
|
2 |
% |
Net income (loss) attributable
to Targa Resources Corp. |
|
387.4 |
|
|
|
220.0 |
|
|
|
167.4 |
|
|
|
76 |
% |
|
|
961.0 |
|
|
|
1,046.3 |
|
|
|
(85.3 |
) |
|
(8 |
%) |
Premium on repurchase of
noncontrolling interests, net of tax |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
490.7 |
|
|
|
(490.7 |
) |
|
(100 |
%) |
Net income (loss) attributable
to common shareholders |
$ |
387.4 |
|
|
$ |
220.0 |
|
|
$ |
167.4 |
|
|
|
76 |
% |
|
$ |
961.0 |
|
|
$ |
555.6 |
|
|
$ |
405.4 |
|
|
73 |
% |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
1,069.7 |
|
|
$ |
840.2 |
|
|
$ |
229.5 |
|
|
|
27 |
% |
|
$ |
3,020.3 |
|
|
$ |
2,570.1 |
|
|
$ |
450.2 |
|
|
18 |
% |
Adjusted cash flow from
operations (1) |
|
884.6 |
|
|
|
667.2 |
|
|
|
217.4 |
|
|
|
33 |
% |
|
|
2,431.7 |
|
|
|
2,060.6 |
|
|
|
371.1 |
|
|
18 |
% |
Adjusted free cash flow
(1) |
|
124.2 |
|
|
|
8.6 |
|
|
|
115.6 |
|
|
NM |
|
|
|
84.2 |
|
|
|
319.1 |
|
|
|
(234.9 |
) |
|
(74 |
%) |
_________________________ |
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Adjusted EBITDA, adjusted cash flow from operations and
adjusted free cash flow are non-GAAP financial measures and are
discussed under “Non-GAAP Financial Measures.” |
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, 2024 Compared to Three
Months Ended September 30, 2023
The decrease in commodity sales reflects lower
natural gas and NGL prices ($504.7 million) and the unfavorable
impact of hedges ($49.2 million), partially offset by higher NGL
volumes ($400.0 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees, higher
transportation fees and higher export volumes, partially offset by
lower fractionation fees.
The decrease in product purchases and fuel
reflects lower natural gas and NGL prices, partially offset by
higher NGL volumes.
The increase in operating expenses is primarily
due to higher labor and maintenance costs as a result of increased
activity and system expansions, partially offset by lower
taxes.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the impact of system expansions on the
Company’s asset base that have been placed in service since
September 30, 2023.
The increase in general and administrative
expense is primarily due to higher compensation and benefits.
The increase in interest expense, net, is due to
higher borrowings, partially offset by an increase in capitalized
interest.
The increase in income tax expense is primarily
due to an increase in pre-tax book income.
Nine Months Ended September 30, 2024 Compared to Nine
Months Ended September 30, 2023
Commodity sales are relatively flat reflecting
lower natural gas prices ($1,051.9 million) and the unfavorable
impact of hedges ($559.2 million), offset by higher NGL, natural
gas and condensate volumes ($1,369.1 million), and higher NGL and
condensate prices ($53.9 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees, higher
transportation fees and higher export volumes.
Product purchases and fuel are relatively flat
reflecting higher NGL and natural gas volumes, offset by lower
natural gas prices.
The increase in operating expenses is primarily
due to higher labor and rental costs as a result of increased
activity and system expansions.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the impact of system expansions on the
Company’s asset base that have been placed in service since
September 30, 2023, partially offset by the shortening of
depreciable lives of certain assets that were idled in the second
quarter of 2023 and subsequently shut down in the third quarter of
2023.
The increase in general and administrative
expense is primarily due to higher compensation and benefits.
The increase in interest expense, net, is due to
recognition of cumulative interest on a 2024 legal ruling
associated with the Splitter Agreement and higher borrowings,
partially offset by an increase in capitalized interest.
The increase in income tax expense is primarily
due to the release of state valuation allowance in 2023, partially
offset by a decrease in pre-tax book income.
The premium on repurchase of noncontrolling
interests, net of tax is due to the acquisition of Blackstone
Energy Partners’ 25% interest in the Grand Prix Joint Venture in
2023.
Review of Segment
Performance
The following discussion of segment performance
includes inter-segment activities. The Company views segment
operating margin and adjusted operating 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 adjusted operating margin, see “Non-GAAP Financial
Measures ― Adjusted Operating Margin.” Segment operating financial
results and operating statistics include the effects of
intersegment transactions. These intersegment transactions have
been eliminated from the consolidated presentation.
The Company operates in two primary segments:
(i) Gathering and Processing; and (ii) Logistics and
Transportation.
Gathering and Processing
Segment
The Gathering and Processing segment includes
assets used in the gathering and/or purchase and sale of natural
gas produced from oil and gas wells, removing impurities and
processing this raw natural gas into merchantable natural gas by
extracting NGLs; and assets used for the gathering and terminaling
and/or purchase and sale of crude oil. The Gathering and Processing
segment’s assets are located in the Permian Basin of West Texas and
Southeast New Mexico (including the Midland, Central 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 (including the Bakken and Three
Forks plays); and the onshore and near offshore regions of the
Louisiana Gulf Coast.
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, |
|
|
|
|
|
|
|
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
|
584.3 |
|
|
$ |
|
505.0 |
|
|
$ |
|
79.3 |
|
|
|
16 |
% |
|
$ |
|
1,713.4 |
|
|
$ |
|
1,545.9 |
|
|
$ |
|
167.5 |
|
|
|
11 |
% |
Operating expenses |
|
|
203.7 |
|
|
|
|
189.6 |
|
|
|
|
14.1 |
|
|
|
7 |
% |
|
|
|
597.2 |
|
|
|
|
560.8 |
|
|
|
|
36.4 |
|
|
|
6 |
% |
Adjusted operating margin |
$ |
|
788.0 |
|
|
$ |
|
694.6 |
|
|
$ |
|
93.4 |
|
|
|
13 |
% |
|
$ |
|
2,310.6 |
|
|
$ |
|
2,106.7 |
|
|
$ |
|
203.9 |
|
|
|
10 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
3,082.0 |
|
|
|
|
2,566.9 |
|
|
|
|
515.1 |
|
|
|
20 |
% |
|
|
|
2,898.8 |
|
|
|
|
2,474.1 |
|
|
|
|
424.7 |
|
|
|
17 |
% |
Permian Delaware |
|
|
2,900.2 |
|
|
|
|
2,485.4 |
|
|
|
|
414.8 |
|
|
|
17 |
% |
|
|
|
2,785.2 |
|
|
|
|
2,513.7 |
|
|
|
|
271.5 |
|
|
|
11 |
% |
Total Permian |
|
|
5,982.2 |
|
|
|
|
5,052.3 |
|
|
|
|
929.9 |
|
|
|
18 |
% |
|
|
|
5,684.0 |
|
|
|
|
4,987.8 |
|
|
|
|
696.2 |
|
|
|
14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
329.9 |
|
|
|
|
394.4 |
|
|
|
|
(64.5 |
) |
|
|
(16 |
%) |
|
|
|
324.8 |
|
|
|
|
373.9 |
|
|
|
|
(49.1 |
) |
|
|
(13 |
%) |
North Texas |
|
|
184.2 |
|
|
|
|
212.0 |
|
|
|
|
(27.8 |
) |
|
|
(13 |
%) |
|
|
|
186.8 |
|
|
|
|
205.2 |
|
|
|
|
(18.4 |
) |
|
|
(9 |
%) |
SouthOK (5) |
|
|
348.5 |
|
|
|
|
394.6 |
|
|
|
|
(46.1 |
) |
|
|
(12 |
%) |
|
|
|
355.7 |
|
|
|
|
391.2 |
|
|
|
|
(35.5 |
) |
|
|
(9 |
%) |
WestOK |
|
|
215.5 |
|
|
|
|
206.2 |
|
|
|
|
9.3 |
|
|
|
5 |
% |
|
|
|
213.6 |
|
|
|
|
207.1 |
|
|
|
|
6.5 |
|
|
|
3 |
% |
Total Central |
|
|
1,078.1 |
|
|
|
|
1,207.2 |
|
|
|
|
(129.1 |
) |
|
|
(11 |
%) |
|
|
|
1,080.9 |
|
|
|
|
1,177.4 |
|
|
|
|
(96.5 |
) |
|
|
(8 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) (6) |
|
|
145.4 |
|
|
|
|
128.3 |
|
|
|
|
17.1 |
|
|
|
13 |
% |
|
|
|
138.8 |
|
|
|
|
129.6 |
|
|
|
|
9.2 |
|
|
|
7 |
% |
Total Field |
|
|
7,205.7 |
|
|
|
|
6,387.8 |
|
|
|
|
817.9 |
|
|
|
13 |
% |
|
|
|
6,903.7 |
|
|
|
|
6,294.8 |
|
|
|
|
608.9 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
402.1 |
|
|
|
|
535.6 |
|
|
|
|
(133.5 |
) |
|
|
(25 |
%) |
|
|
|
464.3 |
|
|
|
|
532.4 |
|
|
|
|
(68.1 |
) |
|
|
(13 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7,607.8 |
|
|
|
|
6,923.4 |
|
|
|
|
684.4 |
|
|
|
10 |
% |
|
|
|
7,368.0 |
|
|
|
|
6,827.2 |
|
|
|
|
540.8 |
|
|
|
8 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
450.6 |
|
|
|
|
373.1 |
|
|
|
|
77.5 |
|
|
|
21 |
% |
|
|
|
422.6 |
|
|
|
|
357.4 |
|
|
|
|
65.2 |
|
|
|
18 |
% |
Permian Delaware |
|
|
377.4 |
|
|
|
|
322.5 |
|
|
|
|
54.9 |
|
|
|
17 |
% |
|
|
|
349.7 |
|
|
|
|
325.3 |
|
|
|
|
24.4 |
|
|
|
8 |
% |
Total Permian |
|
|
828.0 |
|
|
|
|
695.6 |
|
|
|
|
132.4 |
|
|
|
19 |
% |
|
|
|
772.3 |
|
|
|
|
682.7 |
|
|
|
|
89.6 |
|
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
30.6 |
|
|
|
|
42.3 |
|
|
|
|
(11.7 |
) |
|
|
(28 |
%) |
|
|
|
33.9 |
|
|
|
|
42.1 |
|
|
|
|
(8.2 |
) |
|
|
(19 |
%) |
North Texas |
|
|
22.0 |
|
|
|
|
24.2 |
|
|
|
|
(2.2 |
) |
|
|
(9 |
%) |
|
|
|
22.5 |
|
|
|
|
23.8 |
|
|
|
|
(1.3 |
) |
|
|
(5 |
%) |
SouthOK (5) |
|
|
28.4 |
|
|
|
|
46.4 |
|
|
|
|
(18.0 |
) |
|
|
(39 |
%) |
|
|
|
33.3 |
|
|
|
|
44.2 |
|
|
|
|
(10.9 |
) |
|
|
(25 |
%) |
WestOK |
|
|
17.0 |
|
|
|
|
12.3 |
|
|
|
|
4.7 |
|
|
|
38 |
% |
|
|
|
14.7 |
|
|
|
|
12.6 |
|
|
|
|
2.1 |
|
|
|
17 |
% |
Total Central |
|
|
98.0 |
|
|
|
|
125.2 |
|
|
|
|
(27.2 |
) |
|
|
(22 |
%) |
|
|
|
104.4 |
|
|
|
|
122.7 |
|
|
|
|
(18.3 |
) |
|
|
(15 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) |
|
|
18.3 |
|
|
|
|
15.5 |
|
|
|
|
2.8 |
|
|
|
18 |
% |
|
|
|
17.0 |
|
|
|
|
15.5 |
|
|
|
|
1.5 |
|
|
|
10 |
% |
Total Field |
|
|
944.3 |
|
|
|
|
836.3 |
|
|
|
|
108.0 |
|
|
|
13 |
% |
|
|
|
893.7 |
|
|
|
|
820.9 |
|
|
|
|
72.8 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
33.9 |
|
|
|
|
40.6 |
|
|
|
|
(6.7 |
) |
|
|
(17 |
%) |
|
|
|
35.8 |
|
|
|
|
37.9 |
|
|
|
|
(2.1 |
) |
|
|
(6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
978.2 |
|
|
|
|
876.9 |
|
|
|
|
101.3 |
|
|
|
12 |
% |
|
|
|
929.5 |
|
|
|
|
858.8 |
|
|
|
|
70.7 |
|
|
|
8 |
% |
Crude oil, Badlands,
MBbl/d |
|
|
122.4 |
|
|
|
|
101.6 |
|
|
|
|
20.8 |
|
|
|
20 |
% |
|
|
|
105.4 |
|
|
|
|
105.6 |
|
|
|
|
(0.2 |
) |
|
|
— |
|
Crude oil, Permian,
MBbl/d |
|
|
26.7 |
|
|
|
|
27.2 |
|
|
|
|
(0.5 |
) |
|
|
(2 |
%) |
|
|
|
27.4 |
|
|
|
|
27.4 |
|
|
|
|
— |
|
|
|
— |
|
Natural gas sales, BBtu/d
(3) |
|
|
2,842.9 |
|
|
|
|
2,758.2 |
|
|
|
|
84.7 |
|
|
|
3 |
% |
|
|
|
2,779.2 |
|
|
|
|
2,668.4 |
|
|
|
|
110.8 |
|
|
|
4 |
% |
NGL sales, MBbl/d (3) |
|
|
581.5 |
|
|
|
|
508.8 |
|
|
|
|
72.7 |
|
|
|
14 |
% |
|
|
|
550.1 |
|
|
|
|
487.4 |
|
|
|
|
62.7 |
|
|
|
13 |
% |
Condensate sales, MBbl/d |
|
|
17.3 |
|
|
|
|
17.0 |
|
|
|
|
0.3 |
|
|
|
2 |
% |
|
|
|
19.2 |
|
|
|
|
18.7 |
|
|
|
|
0.5 |
|
|
|
3 |
% |
Average realized
prices (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
0.09 |
|
|
|
|
2.03 |
|
|
|
|
(1.94 |
) |
|
|
(96 |
%) |
|
|
|
0.54 |
|
|
|
|
1.97 |
|
|
|
|
(1.43 |
) |
|
|
(73 |
%) |
NGL, $/gal |
|
|
0.44 |
|
|
|
|
0.46 |
|
|
|
|
(0.02 |
) |
|
|
(4 |
%) |
|
|
|
0.45 |
|
|
|
|
0.46 |
|
|
|
|
(0.01 |
) |
|
|
(2 |
%) |
Condensate, $/Bbl |
|
|
77.20 |
|
|
|
|
70.07 |
|
|
|
|
7.13 |
|
|
|
10 |
% |
|
|
|
75.60 |
|
|
|
|
74.20 |
|
|
|
|
1.40 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_________________________ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 period and the denominator is the number of
calendar days during the period. |
(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 a
72.8% undivided interest, and other plants that are owned 100% by
the Company. Operating results for the WestTX undivided interest
assets are presented on a pro-rata net basis in the Company’s
reported financials. |
(5) Operations
include facilities that are not wholly owned by the Company. |
(6) Badlands
natural gas inlet represents the total wellhead volume and includes
the Targa volumes processed at the Little Missouri 4 plant. |
(7) Average
realized prices, net of fees, include the effect of realized
commodity hedge gain/loss attributable to the Company’s equity
volumes. The price is calculated using total commodity sales plus
the hedge gain/loss as the numerator and total sales volume as the
denominator, net of fees. |
|
The following table presents the realized
commodity hedge gain (loss) attributable to the Company’s equity
volumes that are included in the adjusted operating margin of the
Gathering and Processing segment:
|
|
Three Months Ended September 30, 2024 |
|
|
Three Months Ended September 30, 2023 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
Volume Settled |
|
|
Price Spread (1) |
|
|
Gain (Loss) |
|
|
Volume Settled |
|
|
Price Spread (1) |
|
|
Gain (Loss) |
|
Natural gas (BBtu) |
|
|
9.4 |
|
|
$ |
2.53 |
|
|
$ |
23.8 |
|
|
|
15.0 |
|
|
$ |
0.62 |
|
|
$ |
9.3 |
|
NGL (MMgal) |
|
|
102.8 |
|
|
|
0.08 |
|
|
|
8.2 |
|
|
|
166.0 |
|
|
|
0.04 |
|
|
|
7.2 |
|
Crude oil (MBbl) |
|
|
0.6 |
|
|
|
(0.67 |
) |
|
|
(0.4 |
) |
|
|
0.6 |
|
|
|
(13.17 |
) |
|
|
(7.9 |
) |
|
|
|
|
|
|
|
|
$ |
31.6 |
|
|
|
|
|
|
|
|
$ |
8.6 |
|
|
|
Nine Months Ended September 30, 2024 |
|
|
Nine Months Ended September 30, 2023 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
Volume Settled |
|
|
Price Spread (1) |
|
|
Gain (Loss) |
|
|
Volume Settled |
|
|
Price Spread (1) |
|
|
Gain (Loss) |
|
Natural gas (BBtu) |
|
|
35.6 |
|
|
$ |
1.94 |
|
|
$ |
69.2 |
|
|
|
50.0 |
|
|
$ |
1.24 |
|
|
$ |
62.2 |
|
NGL (MMgal) |
|
|
348.9 |
|
|
|
0.04 |
|
|
|
14.9 |
|
|
|
515.0 |
|
|
|
0.07 |
|
|
|
34.4 |
|
Crude oil (MBbl) |
|
|
1.4 |
|
|
|
(5.57 |
) |
|
|
(7.8 |
) |
|
|
1.8 |
|
|
|
(7.17 |
) |
|
|
(12.9 |
) |
|
|
|
|
|
|
|
|
$ |
76.3 |
|
|
|
|
|
|
|
|
$ |
83.7 |
|
_________________________ |
|
(1) The price
spread is the differential between the contracted derivative
instrument pricing and the price of the corresponding settled
commodity transaction. |
|
Three Months Ended September 30, 2024
Compared to Three Months Ended September 30, 2023
The increase in adjusted operating margin was
primarily due to higher natural gas inlet volumes and higher fees
in the Permian, partially offset by lower natural gas prices. The
increase in natural gas inlet volumes in the Permian was
attributable to the addition of the Greenwood I and Wildcat II
plants during the fourth quarter of 2023, the Roadrunner II plant
during the second quarter of 2024, and continued strong producer
activity. The increase in Badlands crude was due to higher
production.
The increase in operating expenses was primarily
due to higher volumes in the Permian and the addition of the
Greenwood I, Wildcat II and Roadrunner II plants in the
Permian.
Nine Months Ended September 30, 2024
Compared to Nine Months Ended September 30, 2023
The increase in adjusted operating margin was
primarily due to higher natural gas inlet volumes and higher fees
in the Permian, partially offset by lower natural gas prices. The
increase in natural gas inlet volumes in the Permian was
attributable to the addition of the Legacy II plant during the
first quarter of 2023, the Midway plant during the second quarter
of 2023, the Greenwood I and Wildcat II plants during the fourth
quarter of 2023, the Roadrunner II plant during the second quarter
of 2024, and continued strong producer activity.
The increase in operating expenses was primarily
due to higher volumes in the Permian and the addition of the Legacy
II, Midway, Greenwood I, Wildcat II and Roadrunner II plants.
Logistics and Transportation
Segment
The Logistics and Transportation 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 LPG
exporters and certain natural gas supply and marketing activities
in support of the Company’s other businesses. The Logistics and
Transportation segment also includes Grand Prix NGL Pipeline, which
connects 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 Company’s
Downstream facilities 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, |
|
|
|
|
|
|
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
|
619.2 |
|
|
$ |
|
457.4 |
|
|
$ |
|
161.8 |
|
|
35 |
% |
|
$ |
|
1,699.0 |
|
|
$ |
|
1,394.4 |
|
|
$ |
|
304.6 |
|
|
22 |
% |
Operating expenses |
|
|
98.1 |
|
|
|
|
88.8 |
|
|
|
|
9.3 |
|
|
10 |
% |
|
|
|
273.5 |
|
|
|
|
247.9 |
|
|
|
|
25.6 |
|
|
10 |
% |
Adjusted operating margin |
$ |
|
717.3 |
|
|
$ |
|
546.2 |
|
|
$ |
|
171.1 |
|
|
31 |
% |
|
$ |
|
1,972.5 |
|
|
$ |
|
1,642.3 |
|
|
$ |
|
330.2 |
|
|
20 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
|
829.2 |
|
|
|
|
660.2 |
|
|
|
|
169.0 |
|
|
26 |
% |
|
|
|
777.0 |
|
|
|
|
606.4 |
|
|
|
|
170.6 |
|
|
28 |
% |
Fractionation volumes |
|
|
953.8 |
|
|
|
|
793.4 |
|
|
|
|
160.4 |
|
|
20 |
% |
|
|
|
884.7 |
|
|
|
|
782.3 |
|
|
|
|
102.4 |
|
|
13 |
% |
Export volumes (3) |
|
|
403.9 |
|
|
|
|
349.3 |
|
|
|
|
54.6 |
|
|
16 |
% |
|
|
|
412.3 |
|
|
|
|
341.9 |
|
|
|
|
70.4 |
|
|
21 |
% |
NGL sales |
|
|
1,162.0 |
|
|
|
|
997.9 |
|
|
|
|
164.1 |
|
|
16 |
% |
|
|
|
1,136.1 |
|
|
|
|
984.1 |
|
|
|
|
152.0 |
|
|
15 |
% |
________________________ |
|
(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) Represents
the total quantity of mixed NGLs that earn a transportation
margin. |
(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 September 30, 2024
Compared to Three Months Ended September 30, 2023
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin,
higher marketing margin, and higher LPG export margin.
Pipeline transportation and fractionation volumes benefited from
higher supply volumes primarily from our Permian Gathering and
Processing systems and the addition of Train 9 during the second
quarter of 2024. Marketing margin increased due to greater
optimization opportunities. LPG export margin increased due
to higher volumes as the company benefited from the completion of
its export expansion during the third quarter of 2023 and the
Houston Ship Channel allowing night-time vessel transits, partially
offset by maintenance and required inspections.
The increase in operating expenses was due to
higher system volumes, higher compensation and benefits, higher
taxes and the addition of Train 9 during the second quarter of
2024.
Nine Months Ended September 30, 2024
Compared to Nine Months Ended September 30, 2023
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin,
higher marketing margin, and higher LPG export margin.
Pipeline transportation and fractionation volumes benefited from
higher supply volumes primarily from our Permian Gathering and
Processing systems and the addition of Train 9 during the second
quarter of 2024. Marketing margin increased due to greater
optimization opportunities. LPG export margin increased due to
higher volumes as the company benefited from the completion of its
export expansion during the third quarter of 2023 and the Houston
Ship Channel allowing night-time vessel transits, partially offset
by maintenance and required inspections.
The increase in operating expenses was due to
higher system volumes, higher compensation and benefits, higher
repairs and maintenance, higher taxes, and the addition of Train 9
during the second quarter of 2024.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
2024 |
|
|
2023 |
|
|
2024 vs. 2023 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
(17.7 |
) |
|
$ |
(33.5 |
) |
|
$ |
15.8 |
|
|
$ |
(86.3 |
) |
|
$ |
294.3 |
|
|
$ |
(380.6 |
) |
Adjusted
operating margin |
|
$ |
(17.7 |
) |
|
$ |
(33.5 |
) |
|
$ |
15.8 |
|
|
$ |
(86.3 |
) |
|
$ |
294.3 |
|
|
$ |
(380.6 |
) |
|
Other contains the results of commodity
derivative activity mark-to-market gains/losses related to
derivative contracts that were not designated as cash flow hedges.
The Company has entered into derivative instruments to hedge the
commodity price associated with a portion of the Company’s future
commodity purchases and sales and natural gas transportation basis
risk within the Company’s Logistics and Transportation segment.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of
midstream services and is one of the largest independent midstream
infrastructure companies in North America. The Company owns,
operates, acquires and develops a diversified portfolio of
complementary domestic midstream infrastructure assets and its
operations are critical to the efficient, safe and reliable
delivery of energy across the United States and increasingly to the
world. The Company’s assets connect natural gas and NGLs to
domestic and international markets with growing demand for cleaner
fuels and feedstocks. The Company is primarily engaged in the
business of: gathering, compressing, treating, processing,
transporting, and purchasing and selling natural gas; transporting,
storing, fractionating, treating, and purchasing and selling NGLs
and NGL products, including services to LPG exporters; and
gathering, storing, terminaling, and purchasing and selling crude
oil.
Targa is a FORTUNE 500 company and is included
in the S&P 500.
For more information, please visit the Company’s
website at www.targaresources.com.
Non-GAAP Financial Measures
This press release includes the Company’s
non-GAAP financial measures: adjusted EBITDA, adjusted cash flow
from operations, adjusted free cash flow and adjusted operating
margin (segment). The following tables provide reconciliations of
these non-GAAP financial measures to their most directly comparable
GAAP measures.
The Company utilizes non-GAAP measures to
analyze the Company’s performance. Adjusted EBITDA, adjusted cash
flow from operations, adjusted free cash flow and adjusted
operating margin (segment) are non-GAAP measures. The GAAP measures
most directly comparable to these non-GAAP measures are income
(loss) from operations, Net income (loss) attributable to Targa
Resources Corp. and segment operating margin. These non-GAAP
measures should not be considered as an alternative to GAAP
measures and have important limitations as analytical tools.
Investors should not consider these measures in isolation or as a
substitute for analysis of the Company’s results as reported under
GAAP. Additionally, because the Company’s non-GAAP measures exclude
some, but not all, items that affect income and segment operating
margin, and are defined differently by different companies within
the Company’s industry, the Company’s definitions may not be
comparable with similarly titled measures of other companies,
thereby diminishing their utility. Management compensates for the
limitations of the Company’s non-GAAP measures as analytical tools
by reviewing the comparable GAAP measures, understanding the
differences between the measures and incorporating these insights
into the Company’s decision-making processes.
Adjusted Operating Margin
The Company defines adjusted operating margin
for the Company’s segments as revenues less product purchases and
fuel. It is impacted by volumes and commodity prices as well as by
the Company’s contract mix and commodity hedging program.
Gathering and Processing adjusted operating
margin consists primarily of:
- service fees related to natural gas and crude oil gathering,
treating and processing; and
- revenues from the sale of natural gas, condensate, crude oil
and NGLs less producer settlements, fuel and transport and the
Company’s equity volume hedge settlements.
Logistics and Transportation adjusted operating
margin consists primarily of:
- service fees (including the pass-through of energy costs
included in certain fee rates);
- system product gains and losses; and
- NGL and natural gas sales, less NGL and natural gas purchases,
fuel, third-party transportation costs and the net inventory
change.
The adjusted operating margin impacts of
mark-to-market hedge unrealized changes in fair value are reported
in Other.
Adjusted operating margin for the Company’s
segments provides useful information to investors because it is
used as a supplemental financial measure 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 capital expenditure projects and acquisitions
and the overall rates of return on alternative investment
opportunities.
Management reviews adjusted operating margin and
operating margin for the Company’s segments 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 the Company’s operating results. The
reconciliation of the Company’s adjusted operating margin to the
most directly comparable GAAP measure is presented under “Review of
Segment Performance.”
Adjusted EBITDA
The Company defines adjusted EBITDA as Net
income (loss) attributable to Targa Resources Corp. 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 the Company’s
financial statements such as investors, commercial banks and others
to measure the ability of the Company’s assets to generate cash
sufficient to pay interest costs, support the Company’s
indebtedness and pay dividends to the Company’s investors.
Adjusted Cash Flow from Operations and Adjusted Free
Cash Flow
The Company defines adjusted cash flow from
operations as adjusted EBITDA less cash interest expense on debt
obligations and cash tax (expense) benefit. The Company defines
adjusted free cash flow as adjusted cash flow from operations less
maintenance capital expenditures (net of any reimbursements of
project costs) and growth capital expenditures, net of
contributions from noncontrolling interest and contributions to
investments in unconsolidated affiliates. Adjusted cash flow from
operations and adjusted free cash flow are performance measures
used by the Company and by external users of the Company’s
financial statements, such as investors, commercial banks and
research analysts, to assess the Company’s ability to generate cash
earnings (after servicing the Company’s debt and funding capital
expenditures) to be used for corporate purposes, such as payment of
dividends, retirement of debt or redemption of other financing
arrangements.
The following table presents a reconciliation of
Net income (loss) attributable to Targa Resources Corp. to adjusted
EBITDA, adjusted cash flow from operations and adjusted free cash
flow for the periods indicated:
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
(In millions) |
|
Reconciliation of Net income (loss) attributable to Targa
Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from
Operations and Adjusted Free Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Corp. |
$ |
387.4 |
|
|
$ |
220.0 |
|
|
$ |
961.0 |
|
|
$ |
1,046.3 |
|
Interest (income) expense, net |
|
184.9 |
|
|
|
175.1 |
|
|
|
589.5 |
|
|
|
509.8 |
|
Income tax expense (benefit) |
|
97.0 |
|
|
|
53.9 |
|
|
|
274.1 |
|
|
|
260.7 |
|
Depreciation and amortization expense |
|
355.4 |
|
|
|
331.3 |
|
|
|
1,044.5 |
|
|
|
988.2 |
|
(Gain) loss on sale or disposition of assets |
|
(1.0 |
) |
|
|
(0.9 |
) |
|
|
(2.7 |
) |
|
|
(3.9 |
) |
Write-down of assets |
|
2.7 |
|
|
|
3.4 |
|
|
|
4.0 |
|
|
|
6.0 |
|
(Gain) loss from financing activities |
|
— |
|
|
|
— |
|
|
|
0.8 |
|
|
|
— |
|
Equity (earnings) loss |
|
(2.2 |
) |
|
|
(3.0 |
) |
|
|
(7.9 |
) |
|
|
(6.2 |
) |
Distributions from unconsolidated affiliates |
|
4.4 |
|
|
|
5.3 |
|
|
|
16.6 |
|
|
|
14.1 |
|
Compensation on equity grants |
|
17.7 |
|
|
|
15.7 |
|
|
|
47.4 |
|
|
|
45.7 |
|
Risk management activities |
|
17.7 |
|
|
|
33.5 |
|
|
|
86.3 |
|
|
|
(294.3 |
) |
Noncontrolling interests adjustments (1) |
|
1.6 |
|
|
|
(1.0 |
) |
|
|
2.6 |
|
|
|
(3.2 |
) |
Litigation expense (2) |
|
4.1 |
|
|
|
6.9 |
|
|
|
4.1 |
|
|
|
6.9 |
|
Adjusted
EBITDA |
$ |
1,069.7 |
|
|
$ |
840.2 |
|
|
$ |
3,020.3 |
|
|
$ |
2,570.1 |
|
Interest expense on debt obligations (3) |
|
(181.2 |
) |
|
|
(172.1 |
) |
|
|
(578.5 |
) |
|
|
(500.9 |
) |
Cash taxes |
|
(3.9 |
) |
|
|
(0.9 |
) |
|
|
(10.1 |
) |
|
|
(8.6 |
) |
Adjusted Cash Flow
from Operations |
$ |
884.6 |
|
|
$ |
667.2 |
|
|
$ |
2,431.7 |
|
|
$ |
2,060.6 |
|
Maintenance capital expenditures, net (4) |
|
(62.0 |
) |
|
|
(65.0 |
) |
|
|
(167.1 |
) |
|
|
(153.0 |
) |
Growth capital expenditures, net (4) |
|
(698.4 |
) |
|
|
(593.6 |
) |
|
|
(2,180.4 |
) |
|
|
(1,588.5 |
) |
Adjusted Free Cash
Flow |
$ |
124.2 |
|
|
$ |
8.6 |
|
|
$ |
84.2 |
|
|
$ |
319.1 |
|
_________________________ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Noncontrolling interest portion of depreciation and amortization
expense. |
(2) Litigation
expense includes charges related to litigation resulting from the
major winter storm in February 2021 that the Company considers
outside the ordinary course of its business and/or not reflective
of its ongoing core operations. The Company may incur such charges
from time to time, and the Company believes it is useful to exclude
such charges because it does not consider them reflective of its
ongoing core operations and because of the generally singular
nature of the claims underlying such litigation. |
(3) Excludes
amortization of interest expense. The nine months ended
September 30, 2024 includes $55.8 million of interest expense
associated with the Splitter Agreement ruling. |
(4) Represents
capital expenditures, net of contributions from noncontrolling
interests and includes contributions to investments in
unconsolidated affiliates |
|
The following table presents a reconciliation of estimated net
income of the Company to estimated adjusted EBITDA for 2024:
|
|
2024E |
|
|
|
(In millions) |
|
Reconciliation of
Estimated Net Income Attributable to Targa Resources Corp.
to |
|
|
|
Estimated Adjusted
EBITDA |
|
|
|
Net income attributable to Targa Resources Corp. |
|
$ |
1,370.0 |
|
Interest expense, net (1) |
|
|
765.0 |
|
Income tax expense |
|
|
375.0 |
|
Depreciation and amortization expense |
|
|
1,370.0 |
|
Equity earnings |
|
|
(5.0 |
) |
Distributions from unconsolidated affiliates |
|
|
20.0 |
|
Compensation on equity grants |
|
|
65.0 |
|
Risk management and other |
|
|
90.0 |
|
Noncontrolling interests adjustments (2) |
|
|
— |
|
Estimated Adjusted EBITDA |
|
$ |
4,050.0 |
|
_________________________ |
|
|
|
|
(1) Includes $55.8
million of interest expense associated with the Splitter Agreement
ruling. |
(2) Noncontrolling
interest portion of depreciation and amortization expense. |
|
Regulation FD Disclosures
The Company uses any of the following to comply
with its disclosure obligations under Regulation FD: press
releases, SEC filings, public conference calls, or our website. The
Company routinely posts important information on its website at
www.targaresources.com, including information that may be deemed to
be material. The Company encourages investors and others interested
in the company to monitor these distribution channels for material
disclosures.
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, including statements regarding our
projected financial performance, capital spending and payment of
future dividends. 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, actions by the
Organization of the Petroleum Exporting Countries (“OPEC”) and
non-OPEC oil producing countries, 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 our completion of capital projects and
business development efforts, the expected growth of volumes on our
systems, the impact of pandemics or any other public health crises,
commodity price volatility due to ongoing or new global conflicts,
the impact of disruptions in the bank and capital markets,
including those resulting from lack of access to liquidity for
banking and financial services firms, 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 most recent Annual Report on
Form 10-K, 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.
Targa Investor
RelationsInvestorRelations@targaresources.com(713) 584-1133
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