Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported second quarter 2023 results.
Second quarter 2023 net income attributable to
Targa Resources Corp. was $329.3 million compared to $596.4 million
for the second quarter of 2022. The Company recognized a $435.9
million gain from sale of an equity method investment in the second
quarter of 2022.
Highlights
- Continue to estimate 2023 adjusted
EBITDA(1) between $3.5 billion and $3.7 billion
- Repurchased $149 million of common
stock during the second quarter and $201 million for the six months
ended June 30, 2023 at a weighted average price of $71.49
- Announced two new Permian gas
plants to meet the infrastructure needs of producers, with no
change to 2023 growth capital expenditure estimate of $2.0 billion
to $2.2 billion
- Reported record Permian natural gas
inlet volumes during the second quarter
- Reported record NGL pipeline
transportation volumes during the second quarter
- Reported record NGL fractionation
volumes during the second quarter
The Company reported adjusted earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“adjusted EBITDA”) of $789.1 million for the second
quarter of 2023 compared to $666.4 million for the second quarter
of 2022. The Company reported distributable cash flow and adjusted
free cash flow for the second quarter of 2023 of $575.8 million and
$(3.7) million, respectively.
On July 13, 2023, the Company declared a
quarterly cash dividend of $0.50 per common share for the second
quarter of 2023, or $2.00 per common share on an annualized basis.
Total cash dividends of approximately $112 million will be paid on
August 15, 2023 on all outstanding shares of common stock to
holders of record as of the close of business on July 31, 2023.
Targa repurchased 2,088,062 shares of its common
stock during the second quarter of 2023 at a weighted average per
share price of $71.37 for a total net cost of $149.0 million. There
was $942.7 million remaining under the Company’s $1.0 billion
common share repurchase program as of June 30, 2023.
Second Quarter 2023 - Sequential Quarter
over Quarter Commentary
Targa reported second quarter 2023 adjusted
EBITDA of $789.1 million, representing a 16 percent decrease when
compared to the first quarter of 2023. The sequential decrease in
adjusted EBITDA was predominantly attributable to lower
optimization margin realized in Targa’s marketing and LPG export
businesses, lower realized natural gas and NGL prices, and higher
operating expenses, partially offset by higher volumes across
Targa’s Gathering and Processing (“G&P”) and Logistics and
Transportation (“L&T”) systems. In the G&P segment, lower
sequential adjusted operating margin was attributable to lower
realized natural gas and NGL prices, partially offset by record
Permian natural gas inlet volumes and higher fees. The increase in
natural gas inlet volumes in the Permian was attributable to
continued high levels of producer activity. In the L&T segment,
significantly lower marketing margin and lower LPG export volumes
drove the sequential decrease in segment adjusted operating margin,
partially offset by higher sequential pipeline transportation and
fractionation volumes. Marketing margin was lower due to reduced
seasonal optimization opportunities. LPG export volumes were lower
due to less demand than the first quarter. Record NGL pipeline
transportation and fractionation volumes were primarily due to
higher supply volumes from Targa’s Permian G&P systems. Higher
operating expenses were primarily attributable to increased
activity levels and additional facilities placed into service.
Capitalization and
Liquidity
The Company’s total consolidated debt as of June
30, 2023 was $12,398.8 million, net of $65.6 million of debt
issuance costs and $40.8 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,
$660.0 million outstanding under the Commercial Paper Program,
$547.9 million outstanding under the Securitization Facility, and
$262.9 million of finance lease liabilities.
Total consolidated liquidity as of June 30, 2023
was approximately $2.2 billion, including $2.1 billion available
under the TRGP Revolver and $169.4 million of cash.
Growth Projects Update
During the second quarter, Targa commenced full
operations at its new 275 million cubic feet per day (“MMcf/d”)
Legacy II plant in Permian Midland and commenced operations at its
new 275 MMcf/d Midway plant in Permian Delaware.
In Permian Midland, construction continues on
Targa’s 275 MMcf/d Greenwood plant. In Permian Delaware, Targa
continues to advance its 275 MMcf/d Wildcat II and 230 MMcf/d
Roadrunner II plants. In its L&T segment, 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.
In August 2023, in response to increasing
production and to meet the infrastructure needs of producers, Targa
announced the construction of a new 275 MMcf/d cryogenic natural
gas processing plant in Permian Midland (the “Greenwood II plant”)
and the construction of a new 275 MMcf/d cryogenic natural gas
processing plant in Permian Delaware (the “Bull Moose plant”). The
Greenwood II and Bull Moose plants are expected to begin operations
in the fourth quarter of 2024 and in the second quarter of 2025,
respectively.
2023 Outlook
While commodity prices are lower than the
assumptions underlying Targa’s previously disclosed full year
financial estimates for 2023, there is no change to Targa’s
expectation to generate full year adjusted EBITDA between $3.5
billion and $3.7 billion for 2023. Targa’s estimate for 2023 total
net growth capital expenditures remains unchanged at between $2.0
billion and $2.2 billion, inclusive of spending on the Greenwood II
and Bull Moose plants. Targa’s estimate for 2023 net maintenance
capital expenditures also remains unchanged at approximately $175
million. Please see the section of this release entitled “Non-GAAP
Financial Measures” for a discussion of forward-looking estimated
adjusted EBITDA and a reconciliation of such measure to its most
directly comparable GAAP financial measure.
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 August 3, 2023 to discuss its second 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/t7tn3qbg. 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 June 30, |
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
2,914.6 |
|
$ |
5,624.2 |
|
$ |
(2,709.6 |
) |
(48 |
%) |
|
$ |
6,939.7 |
|
$ |
10,190.3 |
|
$ |
(3,250.6 |
) |
(32 |
%) |
Fees from midstream services |
|
489.1 |
|
|
431.6 |
|
|
57.5 |
|
13 |
% |
|
|
984.5 |
|
|
824.6 |
|
|
159.9 |
|
19 |
% |
Total revenues |
|
3,403.7 |
|
|
6,055.8 |
|
|
(2,652.1 |
) |
(44 |
%) |
|
|
7,924.2 |
|
|
11,014.9 |
|
|
(3,090.7 |
) |
(28 |
%) |
Product purchases and
fuel |
|
2,068.9 |
|
|
5,047.3 |
|
|
(2,978.4 |
) |
(59 |
%) |
|
|
5,088.0 |
|
|
9,251.5 |
|
|
(4,163.5 |
) |
(45 |
%) |
Operating expenses |
|
272.6 |
|
|
215.8 |
|
|
56.8 |
|
26 |
% |
|
|
530.7 |
|
|
399.3 |
|
|
131.4 |
|
33 |
% |
Depreciation and amortization
expense |
|
332.1 |
|
|
269.9 |
|
|
62.2 |
|
23 |
% |
|
|
656.9 |
|
|
479.0 |
|
|
177.9 |
|
37 |
% |
General and administrative
expense |
|
81.0 |
|
|
71.0 |
|
|
10.0 |
|
14 |
% |
|
|
163.4 |
|
|
138.0 |
|
|
25.4 |
|
18 |
% |
Other operating (income)
expense |
|
— |
|
|
(0.1 |
) |
|
0.1 |
|
100 |
% |
|
|
(0.6 |
) |
|
(0.6 |
) |
|
— |
|
— |
|
Income (loss) from
operations |
|
649.1 |
|
|
451.9 |
|
|
197.2 |
|
44 |
% |
|
|
1,485.8 |
|
|
747.7 |
|
|
738.1 |
|
99 |
% |
Interest expense, net |
|
(166.6 |
) |
|
(81.2 |
) |
|
(85.4 |
) |
105 |
% |
|
|
(334.7 |
) |
|
(174.7 |
) |
|
(160.0 |
) |
92 |
% |
Equity earnings (loss) |
|
3.4 |
|
|
1.4 |
|
|
2.0 |
|
143 |
% |
|
|
3.2 |
|
|
7.0 |
|
|
(3.8 |
) |
(54 |
%) |
Gain (loss) from financing
activities |
|
— |
|
|
(33.8 |
) |
|
33.8 |
|
100 |
% |
|
|
— |
|
|
(49.6 |
) |
|
49.6 |
|
100 |
% |
Gain (loss) from sale of
equity method investment |
|
— |
|
|
435.9 |
|
|
(435.9 |
) |
(100 |
%) |
|
|
— |
|
|
435.9 |
|
|
(435.9 |
) |
(100 |
%) |
Other, net |
|
(2.0 |
) |
|
0.5 |
|
|
(2.5 |
) |
NM |
|
|
|
(4.9 |
) |
|
— |
|
|
(4.9 |
) |
(100 |
%) |
Income tax (expense)
benefit |
|
(96.4 |
) |
|
(87.1 |
) |
|
(9.3 |
) |
11 |
% |
|
|
(206.7 |
) |
|
(110.1 |
) |
|
(96.6 |
) |
88 |
% |
Net income (loss) |
|
387.5 |
|
|
687.6 |
|
|
(300.1 |
) |
(44 |
%) |
|
|
942.7 |
|
|
856.2 |
|
|
86.5 |
|
10 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
58.2 |
|
|
91.2 |
|
|
(33.0 |
) |
(36 |
%) |
|
|
116.4 |
|
|
171.8 |
|
|
(55.4 |
) |
(32 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
329.3 |
|
|
596.4 |
|
|
(267.1 |
) |
(45 |
%) |
|
|
826.3 |
|
|
684.4 |
|
|
141.9 |
|
21 |
% |
Premium on repurchase of
noncontrolling interests, net of tax |
|
— |
|
|
— |
|
|
— |
|
— |
|
|
|
490.7 |
|
|
53.1 |
|
|
437.6 |
|
NM |
|
Dividends on Series A
Preferred Stock |
|
— |
|
|
8.2 |
|
|
(8.2 |
) |
(100 |
%) |
|
|
— |
|
|
30.0 |
|
|
(30.0 |
) |
(100 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
215.5 |
|
|
(215.5 |
) |
(100 |
%) |
|
|
— |
|
|
215.5 |
|
|
(215.5 |
) |
(100 |
%) |
Net income (loss) attributable
to common shareholders |
$ |
329.3 |
|
$ |
372.7 |
|
$ |
(43.4 |
) |
(12 |
%) |
|
$ |
335.6 |
|
$ |
385.8 |
|
$ |
(50.2 |
) |
(13 |
%) |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
789.1 |
|
$ |
666.4 |
|
$ |
122.7 |
|
18 |
% |
|
$ |
1,729.7 |
|
$ |
1,292.1 |
|
$ |
437.6 |
|
34 |
% |
Distributable cash flow
(1) |
|
575.8 |
|
|
533.4 |
|
|
42.4 |
|
8 |
% |
|
|
1,305.2 |
|
|
1,028.2 |
|
|
277.0 |
|
27 |
% |
Adjusted free cash flow
(1) |
|
(3.7 |
) |
|
334.1 |
|
|
(337.8 |
) |
(101 |
%) |
|
|
310.3 |
|
|
707.5 |
|
|
(397.2 |
) |
(56 |
%) |
_________________________
(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 June 30, 2023 Compared to Three Months Ended
June 30, 2022
The decrease in commodity sales reflects lower
NGL, natural gas and condensate prices ($3,412.8 million),
partially offset by higher natural gas, condensate and NGL volumes
($331.5 million) and the favorable impact of hedges ($371.7
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, partially offset by lower export volumes.
The decrease in product purchases and fuel
reflects lower NGL, natural gas and condensate prices, partially
offset by higher natural gas, condensate and NGL volumes.
The increase in operating expenses is primarily
due to increased activity and system expansions, the acquisition of
certain assets in the Delaware Basin and South Texas, and higher
costs attributable to 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, 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,
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 on the Securitization Facility, partially
offset by higher capitalized interest resulting from higher growth
capital investments.
During 2022, the Partnership redeemed its 5.875%
Senior Notes due 2026 (the “5.875% Notes”) resulting in a net loss
from financing activities.
During 2022, the Company completed the sale of
Targa GCX Pipeline LLC to a third party (the “GCX Sale”) resulting
in a gain from sale of an equity method investment.
The increase in income tax expense is primarily
due to a smaller release of the valuation allowance in 2023
compared to 2022, partially offset by a decrease in pre-tax book
income.
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.
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.
Six Months Ended June 30, 2023 Compared to Six
Months Ended June 30, 2022
The decrease in commodity sales reflects lower
NGL, natural gas and condensate prices ($5,197.2 million),
partially offset by higher NGL, natural gas and condensate volumes
($1,028.9 million) and the favorable impact of hedges ($917.7
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, 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 increased activity and system expansions, the acquisition of
certain assets in the Delaware Basin and South Texas, and higher
costs attributable to 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
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 on the Securitization Facility, 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 5.875%
Notes. These transactions resulted in a net loss from financing
activities.
During 2022, the Company completed the GCX Sale
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, the Carnero Joint Venture and Venice
Energy Services, 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
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 June 30, |
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
502.5 |
|
$ |
474.7 |
|
$ |
27.8 |
|
6 |
% |
|
$ |
1,040.9 |
|
$ |
872.3 |
|
$ |
168.6 |
|
19 |
% |
Operating expenses |
|
189.8 |
|
|
141.4 |
|
|
48.4 |
|
34 |
% |
|
|
371.2 |
|
|
258.0 |
|
|
113.2 |
|
44 |
% |
Adjusted operating margin |
$ |
692.3 |
|
$ |
616.1 |
|
$ |
76.2 |
|
12 |
% |
|
$ |
1,412.1 |
|
$ |
1,130.3 |
|
$ |
281.8 |
|
25 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
2,504.3 |
|
|
2,132.0 |
|
|
372.3 |
|
17 |
% |
|
|
2,426.9 |
|
|
2,103.7 |
|
|
323.2 |
|
15 |
% |
Permian Delaware (5) |
|
2,560.8 |
|
|
993.3 |
|
|
1,567.5 |
|
158 |
% |
|
|
2,528.1 |
|
|
985.1 |
|
|
1,543.0 |
|
157 |
% |
Total Permian |
|
5,065.1 |
|
|
3,125.3 |
|
|
1,939.8 |
|
62 |
% |
|
|
4,955.0 |
|
|
3,088.8 |
|
|
1,866.2 |
|
60 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
371.0 |
|
|
271.2 |
|
|
99.8 |
|
37 |
% |
|
|
363.5 |
|
|
216.9 |
|
|
146.6 |
|
68 |
% |
North Texas |
|
208.0 |
|
|
175.3 |
|
|
32.7 |
|
19 |
% |
|
|
201.8 |
|
|
175.3 |
|
|
26.5 |
|
15 |
% |
SouthOK (6) |
|
395.0 |
|
|
460.4 |
|
|
(65.4 |
) |
(14 |
%) |
|
|
389.5 |
|
|
434.0 |
|
|
(44.5 |
) |
(10 |
%) |
WestOK |
|
211.0 |
|
|
212.0 |
|
|
(1.0 |
) |
— |
|
|
|
207.6 |
|
|
207.2 |
|
|
0.4 |
|
— |
|
Total Central |
|
1,185.0 |
|
|
1,118.9 |
|
|
66.1 |
|
6 |
% |
|
|
1,162.4 |
|
|
1,033.4 |
|
|
129.0 |
|
12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) (7) |
|
128.9 |
|
|
129.4 |
|
|
(0.5 |
) |
— |
|
|
|
130.3 |
|
|
127.2 |
|
|
3.1 |
|
2 |
% |
Total Field |
|
6,379.0 |
|
|
4,373.6 |
|
|
2,005.4 |
|
46 |
% |
|
|
6,247.7 |
|
|
4,249.4 |
|
|
1,998.3 |
|
47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
552.1 |
|
|
553.6 |
|
|
(1.5 |
) |
— |
|
|
|
530.7 |
|
|
577.7 |
|
|
(47.0 |
) |
(8 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
6,931.1 |
|
|
4,927.2 |
|
|
2,003.9 |
|
41 |
% |
|
|
6,778.4 |
|
|
4,827.1 |
|
|
1,951.3 |
|
40 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
363.6 |
|
|
310.6 |
|
|
53.0 |
|
17 |
% |
|
|
349.4 |
|
|
305.7 |
|
|
43.7 |
|
14 |
% |
Permian Delaware (5) |
|
367.9 |
|
|
135.8 |
|
|
232.1 |
|
171 |
% |
|
|
355.4 |
|
|
132.8 |
|
|
222.6 |
|
168 |
% |
Total Permian |
|
731.5 |
|
|
446.4 |
|
|
285.1 |
|
64 |
% |
|
|
704.8 |
|
|
438.5 |
|
|
266.3 |
|
61 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
45.6 |
|
|
33.5 |
|
|
12.1 |
|
36 |
% |
|
|
42.0 |
|
|
26.9 |
|
|
15.1 |
|
56 |
% |
North Texas |
|
24.3 |
|
|
19.6 |
|
|
4.7 |
|
24 |
% |
|
|
23.7 |
|
|
19.4 |
|
|
4.3 |
|
22 |
% |
SouthOK (6) |
|
47.3 |
|
|
55.8 |
|
|
(8.5 |
) |
(15 |
%) |
|
|
43.1 |
|
|
53.1 |
|
|
(10.0 |
) |
(19 |
%) |
WestOK |
|
12.5 |
|
|
16.6 |
|
|
(4.1 |
) |
(25 |
%) |
|
|
12.8 |
|
|
15.8 |
|
|
(3.0 |
) |
(19 |
%) |
Total Central |
|
129.7 |
|
|
125.5 |
|
|
4.2 |
|
3 |
% |
|
|
121.6 |
|
|
115.2 |
|
|
6.4 |
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
15.6 |
|
|
14.7 |
|
|
0.9 |
|
6 |
% |
|
|
15.5 |
|
|
14.7 |
|
|
0.8 |
|
5 |
% |
Total Field |
|
876.8 |
|
|
586.6 |
|
|
290.2 |
|
49 |
% |
|
|
841.9 |
|
|
568.4 |
|
|
273.5 |
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
36.8 |
|
|
36.7 |
|
|
0.1 |
|
— |
|
|
|
36.5 |
|
|
36.9 |
|
|
(0.4 |
) |
(1 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
913.6 |
|
|
623.3 |
|
|
290.3 |
|
47 |
% |
|
|
878.4 |
|
|
605.3 |
|
|
273.1 |
|
45 |
% |
Crude oil, Badlands,
MBbl/d |
|
104.7 |
|
|
111.8 |
|
|
(7.1 |
) |
(6 |
%) |
|
|
107.7 |
|
|
117.2 |
|
|
(9.5 |
) |
(8 |
%) |
Crude oil, Permian,
MBbl/d |
|
29.4 |
|
|
28.8 |
|
|
0.6 |
|
2 |
% |
|
|
27.5 |
|
|
29.7 |
|
|
(2.2 |
) |
(7 |
%) |
Natural gas sales, BBtu/d
(3) |
|
2,672.6 |
|
|
2,277.1 |
|
|
395.5 |
|
17 |
% |
|
|
2,622.8 |
|
|
2,202.1 |
|
|
420.7 |
|
19 |
% |
NGL sales, MBbl/d (3) |
|
493.8 |
|
|
440.4 |
|
|
53.4 |
|
12 |
% |
|
|
476.6 |
|
|
432.7 |
|
|
43.9 |
|
10 |
% |
Condensate sales, MBbl/d |
|
24.0 |
|
|
15.7 |
|
|
8.3 |
|
53 |
% |
|
|
21.9 |
|
|
15.0 |
|
|
6.9 |
|
46 |
% |
Average realized
prices (8): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
1.29 |
|
|
6.12 |
|
|
(4.83 |
) |
(79 |
%) |
|
|
1.94 |
|
|
5.15 |
|
|
(3.21 |
) |
(62 |
%) |
NGL, $/gal |
|
0.41 |
|
|
0.89 |
|
|
(0.48 |
) |
(54 |
%) |
|
|
0.47 |
|
|
0.84 |
|
|
(0.37 |
) |
(44 |
%) |
Condensate, $/Bbl |
|
69.52 |
|
|
103.10 |
|
|
(33.58 |
) |
(33 |
%) |
|
|
68.09 |
|
|
90.06 |
|
|
(21.97 |
) |
(24 |
%) |
_________________________
(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 June 30, 2023 |
|
Three Months Ended June 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) |
|
|
15.3 |
|
$ |
1.73 |
|
$ |
26.4 |
|
|
16.7 |
|
$ |
(3.29 |
) |
$ |
(54.9 |
) |
NGL (MMgal) |
|
|
164.9 |
|
|
0.11 |
|
|
17.7 |
|
|
164.4 |
|
|
(0.47 |
) |
|
(77.9 |
) |
Crude oil (MBbl) |
|
|
0.6 |
|
|
(3.67 |
) |
|
(2.2 |
) |
|
0.5 |
|
|
(51.00 |
) |
|
(25.5 |
) |
|
|
|
|
|
|
$ |
41.9 |
|
|
|
|
|
$ |
(158.3 |
) |
|
|
Six Months Ended June 30, 2023 |
|
Six Months Ended June 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) |
|
|
35.0 |
|
$ |
1.51 |
|
$ |
52.9 |
|
|
34.2 |
|
$ |
(2.52 |
) |
$ |
(86.1 |
) |
NGL (MMgal) |
|
|
349.0 |
|
|
0.08 |
|
|
27.2 |
|
|
334.8 |
|
|
(0.47 |
) |
|
(155.8 |
) |
Crude oil (MBbl) |
|
|
1.2 |
|
|
(4.17 |
) |
|
(5.0 |
) |
|
1.0 |
|
|
(45.20 |
) |
|
(45.2 |
) |
|
|
|
|
|
|
$ |
75.1 |
|
|
|
|
|
$ |
(287.1 |
) |
_________________________
(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 June 30, 2023 Compared to
Three Months Ended June 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 primarily 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. 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.
Six Months Ended June 30, 2023 Compared to Six Months Ended June
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 South
Texas and the Delaware Basin. Additionally, higher volumes in the
Permian, the addition of the Legacy I, Red Hills VI and Legacy II
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 June 30, |
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
408.0 |
|
$ |
322.3 |
|
$ |
85.7 |
|
27 |
% |
|
$ |
937.1 |
|
$ |
674.5 |
|
$ |
262.6 |
|
39 |
% |
Operating expenses |
|
82.5 |
|
|
74.4 |
|
|
8.1 |
|
11 |
% |
|
|
159.0 |
|
|
141.3 |
|
|
17.7 |
|
13 |
% |
Adjusted operating margin |
$ |
490.5 |
|
$ |
396.7 |
|
$ |
93.8 |
|
24 |
% |
|
$ |
1,096.1 |
|
$ |
815.8 |
|
$ |
280.3 |
|
34 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
620.7 |
|
|
492.3 |
|
|
128.4 |
|
26 |
% |
|
|
579.0 |
|
|
476.1 |
|
|
102.9 |
|
22 |
% |
Fractionation volumes |
|
794.4 |
|
|
737.2 |
|
|
57.2 |
|
8 |
% |
|
|
776.7 |
|
|
720.1 |
|
|
56.6 |
|
8 |
% |
Export volumes (3) |
|
303.2 |
|
|
342.6 |
|
|
(39.4 |
) |
(12 |
%) |
|
|
338.1 |
|
|
341.7 |
|
|
(3.6 |
) |
(1 |
%) |
NGL sales |
|
947.0 |
|
|
906.9 |
|
|
40.1 |
|
4 |
% |
|
|
977.1 |
|
|
890.0 |
|
|
87.1 |
|
10 |
% |
_________________________
(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 June 30, 2023 Compared to
Three Months Ended June 30, 2022
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin and
higher marketing margin, partially offset by lower LPG export
margin. Pipeline transportation and fractionation volumes benefited
from higher supply volumes primarily from the Company’s Permian
Gathering and Processing systems and higher fees. Marketing margin
increased due to greater optimization opportunities. LPG export
margin decreased due to lower volumes.
The increase in operating expenses was primarily
due to higher equipment rentals and higher compensation and
benefits.
Six Months Ended June 30, 2023 Compared to Six
Months Ended June 30, 2022
The increase in adjusted operating margin was
due to higher marketing margin, higher pipeline transportation and
fractionation margin and higher LPG export margin. Marketing margin
increased due to greater optimization opportunities. Pipeline
transportation and fractionation volumes benefited from higher
supply volumes primarily from the Company’s Permian Gathering and
Processing systems and higher fees. LPG export margin increased
primarily due to lower fuel and power costs.
The increase in operating expenses was due to
higher compensation and benefits, higher taxes and higher equipment
rentals.
Other
|
|
Three Months EndedJune 30, |
|
|
|
Six Months EndedJune 30, |
|
|
|
|
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
2023 |
|
2022 |
|
2023 vs. 2022 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
151.9 |
|
$ |
(4.5 |
) |
$ |
156.4 |
|
$ |
327.7 |
|
$ |
(182.7 |
) |
$ |
510.4 |
|
Adjusted operating margin |
|
$ |
151.9 |
|
$ |
(4.5 |
) |
$ |
156.4 |
|
$ |
327.7 |
|
$ |
(182.7 |
) |
$ |
510.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, |
|
|
Six Months Ended June 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. |
$ |
329.3 |
|
|
$ |
596.4 |
|
|
$ |
826.3 |
|
|
$ |
684.4 |
|
Interest (income) expense, net |
|
166.6 |
|
|
|
81.2 |
|
|
|
334.7 |
|
|
|
174.7 |
|
Income tax expense (benefit) |
|
96.4 |
|
|
|
87.1 |
|
|
|
206.7 |
|
|
|
110.1 |
|
Depreciation and amortization expense |
|
332.1 |
|
|
|
269.9 |
|
|
|
656.9 |
|
|
|
479.0 |
|
(Gain) loss on sale or disposition of assets |
|
(1.7 |
) |
|
|
(0.6 |
) |
|
|
(3.2 |
) |
|
|
(1.6 |
) |
Write-down of assets |
|
1.7 |
|
|
|
0.5 |
|
|
|
2.6 |
|
|
|
1.0 |
|
(Gain) loss from financing activities (1) |
|
— |
|
|
|
33.8 |
|
|
|
— |
|
|
|
49.6 |
|
(Gain) loss from sale of equity method investment |
|
— |
|
|
|
(435.9 |
) |
|
|
— |
|
|
|
(435.9 |
) |
Equity (earnings) loss |
|
(3.4 |
) |
|
|
(1.4 |
) |
|
|
(3.2 |
) |
|
|
(7.0 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
6.2 |
|
|
|
6.8 |
|
|
|
8.8 |
|
|
|
19.3 |
|
Compensation on equity grants |
|
15.0 |
|
|
|
13.8 |
|
|
|
30.0 |
|
|
|
27.3 |
|
Risk management activities |
|
(151.9 |
) |
|
|
4.5 |
|
|
|
(327.7 |
) |
|
|
182.7 |
|
Noncontrolling interests adjustments (2) |
|
(1.2 |
) |
|
|
10.3 |
|
|
|
(2.2 |
) |
|
|
8.5 |
|
Adjusted
EBITDA |
$ |
789.1 |
|
|
$ |
666.4 |
|
|
$ |
1,729.7 |
|
|
$ |
1,292.1 |
|
Interest expense on debt obligations (3) |
|
(163.6 |
) |
|
|
(90.7 |
) |
|
|
(328.8 |
) |
|
|
(182.2 |
) |
Maintenance capital expenditures, net (4) |
|
(46.2 |
) |
|
|
(39.7 |
) |
|
|
(88.0 |
) |
|
|
(77.4 |
) |
Cash taxes |
|
(3.5 |
) |
|
|
(2.6 |
) |
|
|
(7.7 |
) |
|
|
(4.3 |
) |
Distributable Cash
Flow |
$ |
575.8 |
|
|
$ |
533.4 |
|
|
$ |
1,305.2 |
|
|
$ |
1,028.2 |
|
Growth capital expenditures, net (4) |
|
(579.5 |
) |
|
|
(199.3 |
) |
|
|
(994.9 |
) |
|
|
(320.7 |
) |
Adjusted Free Cash
Flow |
$ |
(3.7 |
) |
|
$ |
334.1 |
|
|
$ |
310.3 |
|
|
$ |
707.5 |
|
_________________________
(1) |
Gains or losses on debt repurchases or early debt
extinguishments. |
(2) |
Noncontrolling interest portion
of depreciation and amortization expense. |
(3) |
Excludes amortization of interest
expense. |
(4) |
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. |
$ |
1,440.0 |
|
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 |
|
(330.0 |
) |
Noncontrolling interests adjustments (1) |
|
(5.0 |
) |
Estimated Adjusted EBITDA |
$ |
3,600.0 |
|
_________________________
(1) |
Noncontrolling
interest portion of depreciation and amortization expense. |
|
|
Regulation FD Disclosures
We use any of the following to comply with our
disclosure obligations under Regulation FD: press releases, SEC
filings, public conference calls, or our website. We routinely post
important information on our website at www.targaresources.com,
including information that may be deemed to be material. We
encourage 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 and capital spending. 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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