Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported third quarter 2023 results.
Third quarter 2023 net income attributable to
Targa Resources Corp. was $220.0 million compared to $193.1 million
for the third quarter of 2022.
Highlights
- Reported adjusted EBITDA(1) for the
third quarter of $840 million, a 6% sequential increase
- Reported record NGL transportation
volumes during the third quarter
- Completed its 1 million barrel per
month LPG export expansion at Galena Park
- Completed its new 275 million cubic
feet per day (“MMcf/d”) Greenwood plant in Permian Midland
- Repurchased $132 million of common
stock during the third quarter and $333 million for the nine months
ended September 30, 2023 at a weighted average price of $75.77
- Maintains 2023 adjusted EBITDA
estimate between $3.5 billion and $3.7 billion, with current
expectations trending to the lower end of the range
- No change to 2023 net growth
capital expenditure estimate of $2.0 to $2.2 billion, with current
expectations trending to the higher end of the range
- Strong start to the fourth quarter
with Permian inlet gas volumes currently 150 MMcf/d higher when
compared to average third quarter volumes
- Expect to recommend to Targa’s
Board of Directors an annual common dividend per share of $3.00 in
2024, a 50% increase to 2023, reflective of a continued commitment
to return additional capital to shareholders and the strength of
Targa’s outlook
The Company reported adjusted earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“adjusted EBITDA”) of $840.2 million for the third
quarter of 2023 compared to $768.6 million for the third quarter of
2022. The Company reported distributable cash flow and adjusted
free cash flow for the third quarter of 2023 of $602.2 million and
$8.6 million, respectively.
On October 12, 2023, the Company declared a
quarterly cash dividend of $0.50 per common share for the third
quarter of 2023, or $2.00 per common share on an annualized basis.
Total cash dividends of approximately $112 million will be paid on
November 15, 2023 on all outstanding shares of common stock to
holders of record as of the close of business on October 31,
2023.
Targa repurchased 1,583,317 shares of its common
stock during the third quarter of 2023 at a weighted average per
share price of $83.38 for a total net cost of $132.0 million. There
was $810.7 million remaining under the Company’s $1.0 billion
common share repurchase program as of September 30, 2023.
Third Quarter 2023 - Sequential Quarter
over Quarter Commentary
Targa reported third quarter adjusted EBITDA of
$840.2 million, representing a six percent increase compared to the
second quarter of 2023. The sequential increase in adjusted EBITDA
was primarily attributable to record NGL pipeline transportation
volumes and higher LPG export volumes in Targa’s Logistics and
Transportation (“L&T”) segment, higher realized commodity
prices, and higher fees partially offset by higher expenses. In the
Gathering and Processing (“G&P”) segment, higher sequential
adjusted operating margin was attributable to higher realized
commodity prices, offset by the impacts of the extended stretch of
intense heat in Texas and New Mexico that impacted Targa and our
customers’ operating rates during the third quarter and volumes
from a lower margin high pressure gathering and processing
agreement in the Delaware Basin that moved off our system. Targa’s
Permian volumes are currently about 150 MMcf/d higher than the
third quarter average. In the L&T segment, record NGL pipeline
transportation volumes, higher LPG export volumes, and higher
marketing margin drove the sequential increase in segment adjusted
operating margin. Increasing NGL pipeline transportation volumes
were primarily due to higher third-party supply volumes and LPG
export volumes benefited from improved market conditions. Marketing
margin was higher due to increased seasonal optimization
opportunities. Higher operating expenses were primarily
attributable to system expansions and higher maintenance expenses,
while higher compensation and benefits drove the sequential
increase in general and administrative expenses.
Capitalization and
Liquidity
The Company’s total consolidated debt as of
September 30, 2023 was $12,920.4 million, net of $63.9 million of
debt issuance costs and $40.5 million of unamortized discount, with
$9,534.4 million of outstanding senior notes, $1.5 billion
outstanding under the Company’s $1.5 billion term loan facility,
$1,150.0 million outstanding under the Commercial Paper Program,
$560.0 million outstanding under the Securitization Facility, and
$280.4 million of finance lease liabilities.
Total consolidated liquidity as of September 30,
2023 was approximately $1.8 billion, including $1.6 billion
available under the TRGP Revolver, $139.5 million of cash and $40.0
million available under the Securitization Facility.
Growth Projects Update
In early fourth quarter, Targa commenced
operations at its new 275 MMcf/d Greenwood plant in Permian Midland
ahead of schedule and on-budget. Construction continues on its 275
MMcf/d Greenwood II plant in Permian Midland. In Permian Delaware,
construction continues on the 275 MMcf/d Wildcat II, 230 MMcf/d
Roadrunner II and 275 MMcf/d Bull Moose plants. In its L&T
segment, Targa completed its 1 million barrel per month LPG export
expansion at Galena Park late in the third quarter. Construction
continues on Targa’s 120 thousand barrel per day (“MBbl/d”) Train 9
fractionator and its 120 MBbl/d Train 10 fractionator in Mont
Belvieu, Texas, and its Daytona NGL Pipeline. Targa remains
on-track to complete these expansions as previously disclosed.
2023 Outlook
Targa maintains its 2023 adjusted EBITDA between
$3.5 billion and $3.7 billion, with current expectations trending
to the lower end of the range. Commodity prices are lower than the
assumptions underlying Targa’s previously disclosed full year
financial estimates for 2023 and while Permian Basin volumes have
continued to grow, the growth has been less than initially
projected given weather and operational issues and bottlenecks
associated with compression additions in the Delaware Basin.
Targa’s estimate for 2023 total net growth
capital expenditures remains unchanged at between $2.0 billion and
$2.2 billion, with current expectations trending to the higher end
of the range. Targa’s estimate for 2023 net maintenance capital
expenditures is now approximately $200 million.
Capital Allocation Update
For the first quarter of 2024, Targa intends to
recommend to its Board of Directors an increase to its common
dividend to $0.75 per common share or $3.00 per common share
annualized. The recommended common dividend per share increase, if
approved, would be effective for the first quarter of 2024 and
payable in May 2024. Beyond 2024, Targa expects to be in position
to continue to provide meaningful annual increases to its common
dividend.
For the nine months ended September 30, 2023,
Targa has repurchased 4,395,519 shares of common stock at a
weighted average per share price of $75.77 for a total net cost of
$333.1 million. Targa expects to continue to be in position to
opportunistically repurchase its stock going forward with
approximately $810.7 million remaining under its current common
share repurchase program. Consistent with previous years, Targa
plans to detail its full year 2024 operational and financial
outlook in February 2024 in conjunction with its fourth quarter
2023 earnings announcement.
An earnings supplement presentation and an
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 2, 2023 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/vrp8beac. 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, |
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
3,374.3 |
|
|
$ |
4,800.3 |
|
|
$ |
(1,426.0 |
) |
|
|
(30 |
%) |
|
$ |
10,314.0 |
|
|
$ |
14,990.7 |
|
|
$ |
(4,676.7 |
) |
|
(31 |
%) |
Fees from midstream services |
|
522.3 |
|
|
|
559.8 |
|
|
|
(37.5 |
) |
|
|
(7 |
%) |
|
|
1,506.8 |
|
|
|
1,384.3 |
|
|
|
122.5 |
|
|
9 |
% |
Total revenues |
|
3,896.6 |
|
|
|
5,360.1 |
|
|
|
(1,463.5 |
) |
|
|
(27 |
%) |
|
|
11,820.8 |
|
|
|
16,375.0 |
|
|
|
(4,554.2 |
) |
|
(28 |
%) |
Product purchases and
fuel |
|
2,690.0 |
|
|
|
4,306.3 |
|
|
|
(1,616.3 |
) |
|
|
(38 |
%) |
|
|
7,777.9 |
|
|
|
13,557.8 |
|
|
|
(5,779.9 |
) |
|
(43 |
%) |
Operating expenses |
|
277.7 |
|
|
|
261.3 |
|
|
|
16.4 |
|
|
|
6 |
% |
|
|
808.4 |
|
|
|
660.6 |
|
|
|
147.8 |
|
|
22 |
% |
Depreciation and amortization
expense |
|
331.3 |
|
|
|
287.2 |
|
|
|
44.1 |
|
|
|
15 |
% |
|
|
988.2 |
|
|
|
766.2 |
|
|
|
222.0 |
|
|
29 |
% |
General and administrative
expense |
|
90.0 |
|
|
|
79.1 |
|
|
|
10.9 |
|
|
|
14 |
% |
|
|
253.4 |
|
|
|
217.2 |
|
|
|
36.2 |
|
|
17 |
% |
Other operating (income)
expense |
|
2.5 |
|
|
|
(3.8 |
) |
|
|
6.3 |
|
|
|
166 |
% |
|
|
2.0 |
|
|
|
(4.4 |
) |
|
|
6.4 |
|
|
145 |
% |
Income (loss) from
operations |
|
505.1 |
|
|
|
430.0 |
|
|
|
75.1 |
|
|
|
17 |
% |
|
|
1,990.9 |
|
|
|
1,177.6 |
|
|
|
813.3 |
|
|
69 |
% |
Interest expense, net |
|
(175.1 |
) |
|
|
(125.8 |
) |
|
|
(49.3 |
) |
|
|
39 |
% |
|
|
(509.8 |
) |
|
|
(300.5 |
) |
|
|
(209.3 |
) |
|
70 |
% |
Equity earnings (loss) |
|
3.0 |
|
|
|
1.7 |
|
|
|
1.3 |
|
|
|
76 |
% |
|
|
6.2 |
|
|
|
8.7 |
|
|
|
(2.5 |
) |
|
(29 |
%) |
Gain (loss) from financing
activities |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(49.6 |
) |
|
|
49.6 |
|
|
100 |
% |
Gain (loss) from sale of
equity method investment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
435.9 |
|
|
|
(435.9 |
) |
|
(100 |
%) |
Other, net |
|
(0.1 |
) |
|
|
(14.6 |
) |
|
|
14.5 |
|
|
|
99 |
% |
|
|
(4.9 |
) |
|
|
(14.6 |
) |
|
|
9.7 |
|
|
66 |
% |
Income tax (expense)
benefit |
|
(53.9 |
) |
|
|
(12.0 |
) |
|
|
(41.9 |
) |
|
NM |
|
|
|
(260.7 |
) |
|
|
(122.0 |
) |
|
|
(138.7 |
) |
|
114 |
% |
Net income (loss) |
|
279.0 |
|
|
|
279.3 |
|
|
|
(0.3 |
) |
|
|
— |
|
|
|
1,221.7 |
|
|
|
1,135.5 |
|
|
|
86.2 |
|
|
8 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
59.0 |
|
|
|
86.2 |
|
|
|
(27.2 |
) |
|
|
(32 |
%) |
|
|
175.4 |
|
|
|
258.0 |
|
|
|
(82.6 |
) |
|
(32 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
220.0 |
|
|
|
193.1 |
|
|
|
26.9 |
|
|
|
14 |
% |
|
|
1,046.3 |
|
|
|
877.5 |
|
|
|
168.8 |
|
|
19 |
% |
Premium on repurchase of
noncontrolling interests, net of tax |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
490.7 |
|
|
|
53.1 |
|
|
|
437.6 |
|
NM |
|
Dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
30.0 |
|
|
|
(30.0 |
) |
|
(100 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
215.5 |
|
|
|
(215.5 |
) |
|
(100 |
%) |
Net income (loss) attributable
to common shareholders |
$ |
220.0 |
|
|
$ |
193.1 |
|
|
$ |
26.9 |
|
|
|
14 |
% |
|
$ |
555.6 |
|
|
$ |
578.9 |
|
|
$ |
(23.3 |
) |
|
(4 |
%) |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
840.2 |
|
|
$ |
768.6 |
|
|
$ |
71.6 |
|
|
|
9 |
% |
|
$ |
2,570.1 |
|
|
$ |
2,060.8 |
|
|
$ |
509.3 |
|
|
25 |
% |
Distributable cash flow
(1) |
|
602.2 |
|
|
|
594.9 |
|
|
|
7.3 |
|
|
|
1 |
% |
|
|
1,907.6 |
|
|
|
1,623.2 |
|
|
|
284.4 |
|
|
18 |
% |
Adjusted free cash flow
(1) |
|
8.6 |
|
|
|
290.8 |
|
|
|
(282.2 |
) |
|
|
(97 |
%) |
|
|
319.1 |
|
|
|
998.4 |
|
|
|
(679.3 |
) |
|
(68 |
%) |
(1) Adjusted EBITDA,
distributable cash flow 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, 2023 Compared to Three Months
Ended September 30, 2022
The decrease in commodity sales reflects lower
natural gas, NGL and condensate prices ($2,704.1 million),
partially offset by higher NGL and natural gas volumes ($1,000.1
million) and the favorable impact of hedges ($258.5 million).
The decrease in fees from midstream services is
primarily due to lower gas gathering and processing fees and
transportation and fractionation volumes, partially offset by
higher export volumes.
The decrease in product purchases and fuel
reflects lower natural gas, NGL and condensate prices, partially
offset by higher NGL and natural gas volumes.
The increase in operating expenses is primarily
due to higher labor and maintenance costs due to increased activity
and system expansions, the acquisition of certain assets in the
Delaware Basin and inflation.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the acquisition of certain assets in
the Delaware Basin and the impact of system expansions on the
Company’s asset base, partially offset by the shortening of the
depreciable lives of certain assets that were idled in 2022.
The increase in general and administrative
expense is primarily due to higher compensation and benefits and
insurance costs.
The increase in interest expense, net is due to
higher net borrowings primarily for the acquisition of certain
assets in the Delaware Basin and the Grand Prix Transaction, and
higher interest rates, partially offset by higher capitalized
interest resulting from higher growth capital investments.
The increase in income tax expense is primarily
due to an increase in pre-tax book income and a smaller release of
the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the Grand Prix
Transaction and lower earnings allocated to the Company’s joint
venture partner in WestTX.
Nine Months Ended September 30, 2023 Compared to
Nine Months Ended September 30, 2022
The decrease in commodity sales reflects lower
NGL, natural gas and condensate prices ($7,920.7 million),
partially offset by higher NGL, natural gas and condensate volumes
($2,063.8 million) and the favorable impact of hedges ($1,176.2
million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees including
the impact of the acquisition of certain assets in the Delaware
Basin and South Texas, and higher export fees, partially offset by
lower transportation and fractionation fees.
The decrease in product purchases and fuel
reflects lower NGL, natural gas and condensate prices, partially
offset by higher NGL, natural gas and condensate volumes.
The increase in operating expenses is primarily
due to higher labor and maintenance costs due to increased activity
and system expansions, the acquisition of certain assets in the
Delaware Basin and South Texas, and inflation.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the acquisition of certain assets in
the Delaware Basin and the impact of system expansions on our asset
base, partially offset by the shortening of depreciable lives of
certain assets that were idled in 2022.
The increase in general and administrative
expense is primarily due to higher compensation and benefits,
insurance costs and professional fees.
The increase in interest expense, net is due to
higher net borrowings primarily for the acquisition of certain
assets in the Delaware Basin and the Grand Prix Transaction, and
higher interest rates, partially offset by higher capitalized
interest resulting from higher growth capital investments.
During 2022, the Company terminated the previous
TRGP senior secured revolving credit facility and the Partnership’s
senior secured revolving credit facility. In addition, the
Partnership redeemed its 5.375% Senior Notes due 2027 and its
5.875% Senior Notes due 2026. These transactions resulted in a net
loss from financing activities.
During 2022, the Company completed the sale of
Targa GCX Pipeline LLC to a third party resulting in a gain from
sale of an equity method investment.
The increase in income tax expense is primarily
due to an increase in pre-tax book income and a smaller release of
the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the Grand Prix
Transaction and lower earnings allocated to the Company’s joint
venture partner in WestTX and Venice Energy Services Company,
L.L.C.
The premium on repurchase of noncontrolling
interests, net of tax is due to the Grand Prix Transaction in 2023
and the purchase of all of Stonepeak Infrastructure Partners’
interests in the Company’s development company joint ventures in
2022.
The decrease in dividends on Series A Preferred
Stock (“Series A Preferred”) is due to the full redemption of all
of the Company’s issued and outstanding shares of Series A
Preferred in May 2022.
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 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, |
|
|
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
|
505.0 |
|
|
$ |
|
564.6 |
|
|
$ |
|
(59.6 |
) |
|
|
(11 |
%) |
|
$ |
|
1,545.9 |
|
|
$ |
|
1,437.0 |
|
|
$ |
|
108.9 |
|
|
|
8 |
% |
Operating expenses |
|
|
189.6 |
|
|
|
|
176.6 |
|
|
|
|
13.0 |
|
|
|
7 |
% |
|
|
|
560.8 |
|
|
|
|
434.5 |
|
|
|
|
126.3 |
|
|
|
29 |
% |
Adjusted operating margin |
$ |
|
694.6 |
|
|
$ |
|
741.2 |
|
|
$ |
|
(46.6 |
) |
|
|
(6 |
%) |
|
$ |
|
2,106.7 |
|
|
$ |
|
1,871.5 |
|
|
$ |
|
235.2 |
|
|
|
13 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
2,566.9 |
|
|
|
|
2,307.2 |
|
|
|
|
259.7 |
|
|
|
11 |
% |
|
|
|
2,474.1 |
|
|
|
|
2,172.3 |
|
|
|
|
301.8 |
|
|
|
14 |
% |
Permian Delaware (5) |
|
|
2,485.4 |
|
|
|
|
1,784.8 |
|
|
|
|
700.6 |
|
|
|
39 |
% |
|
|
|
2,513.7 |
|
|
|
|
1,254.6 |
|
|
|
|
1,259.1 |
|
|
|
100 |
% |
Total Permian |
|
|
5,052.3 |
|
|
|
|
4,092.0 |
|
|
|
|
960.3 |
|
|
|
23 |
% |
|
|
|
4,987.8 |
|
|
|
|
3,426.9 |
|
|
|
|
1,560.9 |
|
|
|
46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
|
394.4 |
|
|
|
|
335.5 |
|
|
|
|
58.9 |
|
|
|
18 |
% |
|
|
|
373.9 |
|
|
|
|
256.9 |
|
|
|
|
117.0 |
|
|
|
46 |
% |
North Texas |
|
|
212.0 |
|
|
|
|
177.7 |
|
|
|
|
34.3 |
|
|
|
19 |
% |
|
|
|
205.2 |
|
|
|
|
176.1 |
|
|
|
|
29.1 |
|
|
|
17 |
% |
SouthOK (6) |
|
|
394.6 |
|
|
|
|
400.4 |
|
|
|
|
(5.8 |
) |
|
|
(1 |
%) |
|
|
|
391.2 |
|
|
|
|
422.7 |
|
|
|
|
(31.5 |
) |
|
|
(7 |
%) |
WestOK |
|
|
206.2 |
|
|
|
|
212.8 |
|
|
|
|
(6.6 |
) |
|
|
(3 |
%) |
|
|
|
207.1 |
|
|
|
|
209.1 |
|
|
|
|
(2.0 |
) |
|
|
(1 |
%) |
Total Central |
|
|
1,207.2 |
|
|
|
|
1,126.4 |
|
|
|
|
80.8 |
|
|
|
7 |
% |
|
|
|
1,177.4 |
|
|
|
|
1,064.8 |
|
|
|
|
112.6 |
|
|
|
11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) (7) |
|
|
128.3 |
|
|
|
|
144.8 |
|
|
|
|
(16.5 |
) |
|
|
(11 |
%) |
|
|
|
129.6 |
|
|
|
|
133.1 |
|
|
|
|
(3.5 |
) |
|
|
(3 |
%) |
Total Field |
|
|
6,387.8 |
|
|
|
|
5,363.2 |
|
|
|
|
1,024.6 |
|
|
|
19 |
% |
|
|
|
6,294.8 |
|
|
|
|
4,624.8 |
|
|
|
|
1,670.0 |
|
|
|
36 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
535.6 |
|
|
|
|
539.1 |
|
|
|
|
(3.5 |
) |
|
|
(1 |
%) |
|
|
|
532.4 |
|
|
|
|
564.7 |
|
|
|
|
(32.3 |
) |
|
|
(6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
6,923.4 |
|
|
|
|
5,902.3 |
|
|
|
|
1,021.1 |
|
|
|
17 |
% |
|
|
|
6,827.2 |
|
|
|
|
5,189.5 |
|
|
|
|
1,637.7 |
|
|
|
32 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
373.1 |
|
|
|
|
332.6 |
|
|
|
|
40.5 |
|
|
|
12 |
% |
|
|
|
357.4 |
|
|
|
|
314.8 |
|
|
|
|
42.6 |
|
|
|
14 |
% |
Permian Delaware (5) |
|
|
322.5 |
|
|
|
|
210.9 |
|
|
|
|
111.6 |
|
|
|
53 |
% |
|
|
|
325.3 |
|
|
|
|
159.1 |
|
|
|
|
166.2 |
|
|
|
104 |
% |
Total Permian |
|
|
695.6 |
|
|
|
|
543.5 |
|
|
|
|
152.1 |
|
|
|
28 |
% |
|
|
|
682.7 |
|
|
|
|
473.9 |
|
|
|
|
208.8 |
|
|
|
44 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
|
42.3 |
|
|
|
|
36.4 |
|
|
|
|
5.9 |
|
|
|
16 |
% |
|
|
|
42.1 |
|
|
|
|
30.1 |
|
|
|
|
12.0 |
|
|
|
40 |
% |
North Texas |
|
|
24.2 |
|
|
|
|
20.5 |
|
|
|
|
3.7 |
|
|
|
18 |
% |
|
|
|
23.8 |
|
|
|
|
19.8 |
|
|
|
|
4.0 |
|
|
|
20 |
% |
SouthOK (6) |
|
|
46.4 |
|
|
|
|
48.1 |
|
|
|
|
(1.7 |
) |
|
|
(4 |
%) |
|
|
|
44.2 |
|
|
|
|
51.4 |
|
|
|
|
(7.2 |
) |
|
|
(14 |
%) |
WestOK |
|
|
12.3 |
|
|
|
|
14.8 |
|
|
|
|
(2.5 |
) |
|
|
(17 |
%) |
|
|
|
12.6 |
|
|
|
|
15.4 |
|
|
|
|
(2.8 |
) |
|
|
(18 |
%) |
Total Central |
|
|
125.2 |
|
|
|
|
119.8 |
|
|
|
|
5.4 |
|
|
|
5 |
% |
|
|
|
122.7 |
|
|
|
|
116.7 |
|
|
|
|
6.0 |
|
|
|
5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
|
15.5 |
|
|
|
|
18.0 |
|
|
|
|
(2.5 |
) |
|
|
(14 |
%) |
|
|
|
15.5 |
|
|
|
|
15.8 |
|
|
|
|
(0.3 |
) |
|
|
(2 |
%) |
Total Field |
|
|
836.3 |
|
|
|
|
681.3 |
|
|
|
|
155.0 |
|
|
|
23 |
% |
|
|
|
820.9 |
|
|
|
|
606.4 |
|
|
|
|
214.5 |
|
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
40.6 |
|
|
|
|
31.7 |
|
|
|
|
8.9 |
|
|
|
28 |
% |
|
|
|
37.9 |
|
|
|
|
35.1 |
|
|
|
|
2.8 |
|
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
876.9 |
|
|
|
|
713.0 |
|
|
|
|
163.9 |
|
|
|
23 |
% |
|
|
|
858.8 |
|
|
|
|
641.5 |
|
|
|
|
217.3 |
|
|
|
34 |
% |
Crude oil, Badlands,
MBbl/d |
|
|
101.6 |
|
|
|
|
122.2 |
|
|
|
|
(20.6 |
) |
|
|
(17 |
%) |
|
|
|
105.6 |
|
|
|
|
118.9 |
|
|
|
|
(13.3 |
) |
|
|
(11 |
%) |
Crude oil, Permian,
MBbl/d |
|
|
27.2 |
|
|
|
|
30.3 |
|
|
|
|
(3.1 |
) |
|
|
(10 |
%) |
|
|
|
27.4 |
|
|
|
|
29.9 |
|
|
|
|
(2.5 |
) |
|
|
(8 |
%) |
Natural gas sales, BBtu/d
(3) |
|
|
2,758.2 |
|
|
|
|
2,458.1 |
|
|
|
|
300.1 |
|
|
|
12 |
% |
|
|
|
2,668.4 |
|
|
|
|
2,288.4 |
|
|
|
|
380.0 |
|
|
|
17 |
% |
NGL sales, MBbl/d (3) |
|
|
508.8 |
|
|
|
|
436.1 |
|
|
|
|
72.7 |
|
|
|
17 |
% |
|
|
|
487.4 |
|
|
|
|
433.8 |
|
|
|
|
53.6 |
|
|
|
12 |
% |
Condensate sales, MBbl/d |
|
|
17.0 |
|
|
|
|
15.5 |
|
|
|
|
1.5 |
|
|
|
10 |
% |
|
|
|
18.7 |
|
|
|
|
15.2 |
|
|
|
|
3.5 |
|
|
|
23 |
% |
Average realized
prices (8): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
2.03 |
|
|
|
|
6.71 |
|
|
|
|
(4.68 |
) |
|
|
(70 |
%) |
|
|
|
1.97 |
|
|
|
|
5.71 |
|
|
|
|
(3.74 |
) |
|
|
(65 |
%) |
NGL, $/gal |
|
|
0.46 |
|
|
|
|
0.77 |
|
|
|
|
(0.31 |
) |
|
|
(40 |
%) |
|
|
|
0.46 |
|
|
|
|
0.82 |
|
|
|
|
(0.36 |
) |
|
|
(44 |
%) |
Condensate, $/Bbl |
|
|
70.07 |
|
|
|
|
96.41 |
|
|
|
|
(26.34 |
) |
|
|
(27 |
%) |
|
|
|
74.20 |
|
|
|
|
92.25 |
|
|
|
|
(18.05 |
) |
|
|
(20 |
%) |
(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) Includes operations from the
acquisition of certain assets in the Delaware Basin for the period
effective August 1, 2022.(6) Operations
include facilities that are not wholly owned by the Company.
SouthTX operating statistics include the impact of the acquisition
of certain assets in South Texas for the period effective April 21,
2022.(7) Badlands natural gas inlet
represents the total wellhead volume and includes the Targa volumes
processed at the Little Missouri 4
plant.(8) 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, 2023 |
|
|
Three Months Ended September 30, 2022 |
|
|
|
(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) |
|
|
15.0 |
|
|
$ |
0.62 |
|
|
$ |
9.3 |
|
|
|
20.3 |
|
|
$ |
(3.58 |
) |
|
$ |
(72.7 |
) |
NGL (MMgal) |
|
|
166.0 |
|
|
|
0.04 |
|
|
|
7.2 |
|
|
|
194.9 |
|
|
|
(0.25 |
) |
|
|
(49.4 |
) |
Crude oil (MBbl) |
|
|
0.6 |
|
|
|
(13.17 |
) |
|
|
(7.9 |
) |
|
|
0.6 |
|
|
|
(26.83 |
) |
|
|
(16.1 |
) |
|
|
|
|
|
|
|
|
$ |
8.6 |
|
|
|
|
|
|
|
|
$ |
(138.2 |
) |
|
|
Nine Months Ended September 30, 2023 |
|
|
Nine Months Ended September 30, 2022 |
|
|
|
(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) |
|
|
50.0 |
|
|
$ |
1.24 |
|
|
$ |
62.2 |
|
|
|
54.5 |
|
|
$ |
(2.91 |
) |
|
$ |
(158.8 |
) |
NGL (MMgal) |
|
|
515.0 |
|
|
|
0.07 |
|
|
|
34.4 |
|
|
|
529.7 |
|
|
|
(0.39 |
) |
|
|
(205.2 |
) |
Crude oil (MBbl) |
|
|
1.8 |
|
|
|
(7.17 |
) |
|
|
(12.9 |
) |
|
|
1.6 |
|
|
|
(38.31 |
) |
|
|
(61.3 |
) |
|
|
|
|
|
|
|
|
$ |
83.7 |
|
|
|
|
|
|
|
|
$ |
(425.3 |
) |
(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, 2023 Compared to Three
Months Ended September 30, 2022
The decrease in adjusted operating margin was
due to lower commodity prices, partially offset by higher natural
gas inlet volumes and higher fees predominantly in the Permian. The
increase in natural gas inlet volumes in the Permian was
attributable to the acquisition of certain assets in the Delaware
Basin during the third quarter of 2022, the addition of the Legacy
I and Red Hills VI plants during the third quarter of 2022 and the
Legacy II plant late in the first quarter of 2023, and continued
strong producer activity. The natural gas inlet volumes in the
Central region increased primarily due to increased producer
activity during the third quarter of 2023.
The increase in operating expenses was
predominantly due to the acquisition of certain assets in the
Delaware Basin. Additionally, higher volumes in the Permian, the
addition of the Legacy I, Red Hills VI, Legacy II and Midway
plants, and inflation impacts resulted in increased costs.
Nine Months Ended September 30, 2023 Compared to Nine Months
Ended September 30, 2022
The increase in adjusted operating margin was
due to higher natural gas inlet volumes and higher fees resulting
in increased margin predominantly in the Permian, partially offset
by lower commodity prices. The increase in natural gas inlet
volumes in the Permian was attributable to the acquisition of
certain assets in the Delaware Basin during the third quarter of
2022, the addition of the Legacy I and Red Hills VI plants during
the third quarter of 2022 and the Legacy II plant late in the first
quarter of 2023, and continued strong producer activity. Natural
gas inlet volumes in the Central region increased due to the
acquisition of certain assets in South Texas during the second
quarter of 2022 and increased producer activity.
The increase in operating expenses was
predominantly due to the acquisition of certain assets in the
Delaware Basin and South Texas. Additionally, higher volumes in the
Permian, the addition of the Legacy I, Red Hills VI, Legacy II and
Midway plants, and inflation impacts resulted in increased
costs.
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 associated assets
are generally connected to and supplied in part by the Company’s
Gathering and Processing segment and, except for the 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, |
|
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
|
457.4 |
|
|
$ |
|
340.2 |
|
|
$ |
|
117.2 |
|
|
34 |
% |
|
$ |
|
1,394.4 |
|
|
$ |
|
1,014.6 |
|
|
$ |
|
379.8 |
|
|
37 |
% |
Operating expenses |
|
|
88.8 |
|
|
|
|
84.5 |
|
|
|
|
4.3 |
|
|
5 |
% |
|
|
|
247.9 |
|
|
|
|
225.8 |
|
|
|
|
22.1 |
|
|
10 |
% |
Adjusted operating margin |
$ |
|
546.2 |
|
|
$ |
|
424.7 |
|
|
$ |
|
121.5 |
|
|
29 |
% |
|
$ |
|
1,642.3 |
|
|
$ |
|
1,240.4 |
|
|
$ |
|
401.9 |
|
|
32 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
|
660.2 |
|
|
|
|
499.5 |
|
|
|
|
160.7 |
|
|
32 |
% |
|
|
|
606.4 |
|
|
|
|
484.0 |
|
|
|
|
122.4 |
|
|
25 |
% |
Fractionation volumes |
|
|
793.4 |
|
|
|
|
742.1 |
|
|
|
|
51.3 |
|
|
7 |
% |
|
|
|
782.3 |
|
|
|
|
727.5 |
|
|
|
|
54.8 |
|
|
8 |
% |
Export volumes (3) |
|
|
349.3 |
|
|
|
|
276.1 |
|
|
|
|
73.2 |
|
|
27 |
% |
|
|
|
341.9 |
|
|
|
|
319.6 |
|
|
|
|
22.3 |
|
|
7 |
% |
NGL sales |
|
|
997.9 |
|
|
|
|
825.0 |
|
|
|
|
172.9 |
|
|
21 |
% |
|
|
|
984.1 |
|
|
|
|
868.1 |
|
|
|
|
116.0 |
|
|
13 |
% |
(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, 2023
Compared to Three Months Ended September 30, 2022
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin,
higher LPG export margin and higher marketing margin. Pipeline
transportation and fractionation volumes benefited from higher
supply volumes primarily from our Permian Gathering and Processing
systems and higher fees. LPG export margin increased due to higher
volumes. Marketing margin increased due to greater optimization
opportunities.
The increase in operating expenses was primarily
due to higher compensation and benefits, and higher costs
attributable to inflation.
Nine Months Ended September 30, 2023 Compared to
Nine Months Ended September 30, 2022
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 higher fees. Marketing margin increased due to greater
optimization opportunities. LPG Export margin increased primarily
due to higher volumes and lower fuel and power costs.
The increase in operating expenses was due to
higher compensation and benefits, taxes, repairs and maintenance,
and higher costs attributable to inflation.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
(33.5 |
) |
|
$ |
(112.2 |
) |
|
$ |
78.7 |
|
|
$ |
294.3 |
|
|
$ |
(294.9 |
) |
|
$ |
589.2 |
|
Adjusted operating margin |
|
$ |
(33.5 |
) |
|
$ |
(112.2 |
) |
|
$ |
78.7 |
|
|
$ |
294.3 |
|
|
$ |
(294.9 |
) |
|
$ |
589.2 |
|
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, distributable cash
flow, 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, distributable
cash flow, 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.
Distributable Cash Flow and Adjusted Free Cash
Flow
The Company defines distributable cash flow as
adjusted EBITDA less cash interest expense on debt obligations,
cash tax (expense) benefit and maintenance capital expenditures
(net of any reimbursements of project costs). The Company defines
adjusted free cash flow as distributable cash flow less growth
capital expenditures, net of contributions from noncontrolling
interest and net contributions to investments in unconsolidated
affiliates. Distributable cash flow 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, distributable cash flow and adjusted free cash flow for the
periods indicated:
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
|
(In millions) |
|
Reconciliation of Net
income (loss) attributable to Targa Resources Corp. to Adjusted
EBITDA, Distributable Cash Flow and Adjusted Free Cash
Flow |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Corp. |
$ |
220.0 |
|
|
$ |
193.1 |
|
|
$ |
1,046.3 |
|
|
$ |
877.5 |
|
Interest (income) expense, net |
|
175.1 |
|
|
|
125.8 |
|
|
|
509.8 |
|
|
|
300.5 |
|
Income tax expense (benefit) |
|
53.9 |
|
|
|
12.0 |
|
|
|
260.7 |
|
|
|
122.0 |
|
Depreciation and amortization expense |
|
331.3 |
|
|
|
287.2 |
|
|
|
988.2 |
|
|
|
766.2 |
|
(Gain) loss on sale or disposition of assets |
|
(0.9 |
) |
|
|
(6.5 |
) |
|
|
(3.9 |
) |
|
|
(8.1 |
) |
Write-down of assets |
|
3.4 |
|
|
|
2.7 |
|
|
|
6.0 |
|
|
|
3.7 |
|
(Gain) loss from financing activities (1) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
49.6 |
|
(Gain) loss from sale of equity method investment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(435.9 |
) |
Transaction costs related to business acquisition (2) |
|
— |
|
|
|
20.3 |
|
|
|
— |
|
|
|
20.3 |
|
Equity (earnings) loss |
|
(3.0 |
) |
|
|
(1.7 |
) |
|
|
(6.2 |
) |
|
|
(8.7 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
5.3 |
|
|
|
2.4 |
|
|
|
14.1 |
|
|
|
21.7 |
|
Compensation on equity grants |
|
15.7 |
|
|
|
14.4 |
|
|
|
45.7 |
|
|
|
41.8 |
|
Risk management activities |
|
33.5 |
|
|
|
112.2 |
|
|
|
(294.3 |
) |
|
|
295.0 |
|
Noncontrolling interests adjustments (3) |
|
(1.0 |
) |
|
|
6.7 |
|
|
|
(3.2 |
) |
|
|
15.2 |
|
Litigation expense (4) |
|
6.9 |
|
|
|
— |
|
|
|
6.9 |
|
|
|
— |
|
Adjusted
EBITDA |
$ |
840.2 |
|
|
$ |
768.6 |
|
|
$ |
2,570.1 |
|
|
$ |
2,060.8 |
|
Interest expense on debt obligations (5) |
|
(172.1 |
) |
|
|
(123.0 |
) |
|
|
(500.9 |
) |
|
|
(305.2 |
) |
Maintenance capital expenditures, net (6) |
|
(65.0 |
) |
|
|
(49.4 |
) |
|
|
(153.0 |
) |
|
|
(126.8 |
) |
Cash taxes |
|
(0.9 |
) |
|
|
(1.3 |
) |
|
|
(8.6 |
) |
|
|
(5.6 |
) |
Distributable Cash
Flow |
$ |
602.2 |
|
|
$ |
594.9 |
|
|
$ |
1,907.6 |
|
|
$ |
1,623.2 |
|
Growth capital expenditures, net (6) |
|
(593.6 |
) |
|
|
(304.1 |
) |
|
|
(1,588.5 |
) |
|
|
(624.8 |
) |
Adjusted Free Cash
Flow |
$ |
8.6 |
|
|
$ |
290.8 |
|
|
$ |
319.1 |
|
|
$ |
998.4 |
|
(1) Gains or losses on
debt repurchases or early debt
extinguishments.(2) Includes financial
advisory, legal and other professional fees, and other one-time
transaction costs.(3) Noncontrolling
interest portion of depreciation and amortization
expense.(4) 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.(5) Excludes amortization of debt
issuance costs.(6) Represents capital expenditures, net of
contributions from noncontrolling interests and includes net
contributions to investments in unconsolidated affiliates.
The following table presents a reconciliation of estimated net
income of the Company to estimated adjusted EBITDA for 2023:
|
2023E |
|
|
(In millions) |
|
Reconciliation of
Estimated Net Income Attributable to Targa Resources Corp.
to |
|
|
Estimated Adjusted
EBITDA |
|
|
Net income attributable to Targa Resources Corp. |
$ |
1,403.0 |
|
Interest expense, net |
|
700.0 |
|
Income tax expense |
|
400.0 |
|
Depreciation and amortization expense |
|
1,320.0 |
|
Equity earnings |
|
(10.0 |
) |
Distributions from unconsolidated affiliates |
|
25.0 |
|
Compensation on equity grants |
|
60.0 |
|
Risk management and other (1) |
|
(293.0 |
) |
Noncontrolling interests adjustments (2) |
|
(5.0 |
) |
Estimated Adjusted EBITDA |
$ |
3,600.0 |
|
(1) Other includes litigation
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.(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, 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 impact of pandemics or any other public health crises,
commodity price volatility due to ongoing or new global conflicts,
actions by the Organization of the Petroleum Exporting Countries
(“OPEC”) and non-OPEC oil producing countries, 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, 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 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.
Contact the Company’s investor relations
department by email at InvestorRelations@targaresources.com or by
phone at (713) 584-1133.
Sanjay LadVice President, Finance & Investor
Relations
Jennifer KnealeChief Financial Officer
Targa Resources (NYSE:TRGP)
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