Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported third quarter 2022 results.
Third Quarter 2022 Financial
Results
Third quarter 2022 net income attributable to
Targa Resources Corp. was $193.1 million compared to $182.2 million
for the third quarter of 2021.
The Company reported record adjusted earnings
before interest, income taxes, depreciation and amortization, and
other non-cash items (“adjusted EBITDA”) of $768.6 million for the
third quarter of 2022 compared to $505.9 million for the third
quarter of 2021.
On October 13, 2022, Targa declared a quarterly
dividend of $0.35 per share of its common stock for the third
quarter of 2022, or $1.40 per share on an annualized basis. Total
cash dividends of approximately $79 million will be paid on
November 15, 2022 on all outstanding shares of common stock to
holders of record as of the close of business on October 31,
2022.
Targa repurchased 1,156,832 shares of its common
stock during the third quarter of 2022 at a weighted average price
of $63.06 for a total net cost of $72.9 million. There was $171.8
million remaining under the Company’s $500 million common share
repurchase program as of September 30, 2022.
The Company reported distributable cash flow and
adjusted free cash flow for the third quarter of 2022 of $594.9
million and $290.8 million, respectively.
Third Quarter 2022 - Sequential Quarter over Quarter
Commentary
Targa reported third quarter 2022 adjusted
EBITDA of $768.6 million, representing a 15 percent increase when
compared to the second quarter of 2022. The sequential increase in
adjusted EBITDA was primarily attributable to higher volumes across
Targa’s Gathering and Processing (“G&P”) and Logistics and
Transportation (“L&T”) systems, partially offset by lower
natural gas liquids (“NGL”) and condensate prices and higher
operating expenses. Higher sequential adjusted operating margin in
the G&P segment was driven by contributions from the Company’s
Delaware Basin acquisition, which closed with an accounting
effective date of August 1, 2022, and higher natural gas inlet
volumes across Permian, Central, and Badlands partially offset by
lower volumes in SouthOK resulting from a contract expiration.
Permian natural gas inlet volumes averaged a record 4.1 billion
cubic feet per day (“Bcf/d”) in the third quarter. In the L&T
segment, the sequential increase in segment adjusted operating
margin was attributable to higher pipeline transportation and
fractionation volumes and higher marketing margin, partially offset
by lower LPG export margin. NGL pipeline transportation and
fractionation volumes achieved record levels during the third
quarter primarily due to higher supply volumes from Targa’s Permian
G&P systems and third parties. Marketing margin was higher due
to greater optimization opportunities while the decrease in LPG
export margin was due to lower volumes. Higher operating expenses
were attributable to the Delaware Basin acquisition, higher
activity levels, and higher costs from the impacts of
inflation.
Capitalization and Liquidity
In September 2022, the Company amended the
accounts receivable securitization facility (the “Securitization
Facility”), primarily to increase the size of the Securitization
Facility from $400.0 million to $800.0 million and extend the
Securitization Facility termination date to September 1, 2023.
The Company’s total consolidated debt as of
September 30, 2022 was $11,197.8 million, net of $66.5 million of
debt issuance costs and $8.5 million of unamortized discount, with
$7,784.4 million of outstanding senior notes, $1.5 billion
outstanding under the Company’s $1.5 billion term loan facility,
$550.0 million outstanding under the Company’s $2.75 billion senior
revolving credit facility (the “TRGP Revolver”), $632.0 million
outstanding under the Company’s unsecured commercial paper note
program, $750.0 million outstanding under the Securitization
Facility and $56.4 million of finance lease liabilities.
Total consolidated liquidity as of September 30, 2022 was
approximately $1.8 billion, including $1.5 billion available under
the TRGP Revolver, $192.9 million of cash and $50.0 million
available under the Securitization Facility.
Growth Projects Update
During the third quarter, Targa commenced
operations at its new 275 million cubic feet per day (“MMcf/d”)
Legacy plant in Permian Midland and its new 230 MMcf/d Red Hills VI
plant in Permian Delaware.
Construction continues on Targa’s 275 MMcf/d
Legacy II plant and 275 MMcf/d Greenwood plant in Permian Midland,
its 275 MMcf/d Midway plant in Permian Delaware, and its 120
thousand barrels per day (“MBbl/d”) Train 9 fractionator in Mont
Belvieu.
In November 2022, 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 Delaware (the “Wildcat II plant”),
which is expected to begin operations in the first quarter of
2024.
In November 2022, supported by the growth in
NGLs from Targa’s underlying assets and future plant additions,
Targa announced plans to construct the Daytona NGL Pipeline as an
addition to Targa's existing common carrier Grand Prix NGL Pipeline
system. The Daytona NGL Pipeline will transport NGLs from the
Permian Basin and connect to the 30-inch diameter segment of
Targa's Grand Prix NGL Pipeline in North Texas, where volumes will
be transported to Targa’s fractionation and storage complex in Mont
Belvieu. The Daytona NGL Pipeline is expected to be in service by
the end of 2024, at an estimated cost of approximately $650
million. Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"),
of which Targa owns 75% and Blackstone Energy Partners owns 25%,
will own the Daytona NGL Pipeline and each member will fund their
respective share of the pipeline’s cost based on their ownership
percentage. Targa is constructing and operating the Daytona NGL
Pipeline. Targa expects to fund the construction of the Daytona NGL
Pipeline through the utilization of operating cash flows and
available liquidity.
2022 Outlook
While commodity prices were significantly lower
in the third quarter than the assumptions underlying Targa’s last
provided financial estimates for 2022, there is no change to the
Company’s expectation to generate full year adjusted EBITDA between
$2.85 billion and $2.95 billion.
Through September 30, 2022, Targa has spent
$624.8 million on net growth capital expenditures and now estimates
total net growth capital expenditures for 2022 to be between $1.1
billion and $1.2 billion including spending accelerated into 2022
for the new Wildcat II plant and the Daytona NGL Pipeline. Targa’s
estimate for 2022 net maintenance capital expenditures remains
unchanged at approximately $150 million.
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 3, 2022 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/8vx55eqq. A webcast replay will
be available at the link above approximately two hours after the
conclusion of the event.
Targa Resources Corp. – Consolidated
Financial Results of Operations
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
4,800.3 |
|
|
$ |
4,118.1 |
|
|
$ |
682.2 |
|
|
|
17 |
% |
|
$ |
14,990.7 |
|
|
$ |
10,577.3 |
|
|
$ |
4,413.4 |
|
|
42 |
% |
Fees from midstream services |
|
559.8 |
|
|
|
341.6 |
|
|
|
218.2 |
|
|
|
64 |
% |
|
|
1,384.3 |
|
|
|
930.9 |
|
|
|
453.4 |
|
|
49 |
% |
Total revenues |
|
5,360.1 |
|
|
|
4,459.7 |
|
|
|
900.4 |
|
|
|
20 |
% |
|
|
16,375.0 |
|
|
|
11,508.2 |
|
|
|
4,866.8 |
|
|
42 |
% |
Product purchases and
fuel |
|
4,306.3 |
|
|
|
3,614.7 |
|
|
|
691.6 |
|
|
|
19 |
% |
|
|
13,557.8 |
|
|
|
9,159.8 |
|
|
|
4,398.0 |
|
|
48 |
% |
Operating expenses |
|
261.3 |
|
|
|
189.4 |
|
|
|
71.9 |
|
|
|
38 |
% |
|
|
660.6 |
|
|
|
545.3 |
|
|
|
115.3 |
|
|
21 |
% |
Depreciation and amortization
expense |
|
287.2 |
|
|
|
222.8 |
|
|
|
64.4 |
|
|
|
29 |
% |
|
|
766.2 |
|
|
|
650.9 |
|
|
|
115.3 |
|
|
18 |
% |
General and administrative
expense |
|
79.1 |
|
|
|
67.3 |
|
|
|
11.8 |
|
|
|
18 |
% |
|
|
217.2 |
|
|
|
192.4 |
|
|
|
24.8 |
|
|
13 |
% |
Other operating (income)
expense |
|
(3.8 |
) |
|
|
(1.0 |
) |
|
|
(2.8 |
) |
|
|
280 |
% |
|
|
(4.4 |
) |
|
|
3.4 |
|
|
|
(7.8 |
) |
|
(229 |
%) |
Income (loss) from
operations |
|
430.0 |
|
|
|
366.5 |
|
|
|
63.5 |
|
|
|
17 |
% |
|
|
1,177.6 |
|
|
|
956.4 |
|
|
|
221.2 |
|
|
23 |
% |
Interest expense, net |
|
(125.8 |
) |
|
|
(91.0 |
) |
|
|
(34.8 |
) |
|
|
38 |
% |
|
|
(300.5 |
) |
|
|
(284.2 |
) |
|
|
(16.3 |
) |
|
6 |
% |
Equity earnings (loss) |
|
1.7 |
|
|
|
14.3 |
|
|
|
(12.6 |
) |
|
|
(88 |
%) |
|
|
8.7 |
|
|
|
38.9 |
|
|
|
(30.2 |
) |
|
(78 |
%) |
Gain (loss) from financing
activities |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(49.6 |
) |
|
|
(16.6 |
) |
|
|
(33.0 |
) |
|
199 |
% |
Gain (loss) from sale of
equity method investment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
435.9 |
|
|
|
— |
|
|
|
435.9 |
|
|
100 |
% |
Other, net |
|
(14.6 |
) |
|
|
0.2 |
|
|
|
(14.8 |
) |
|
NM |
|
|
|
(14.6 |
) |
|
|
0.3 |
|
|
|
(14.9 |
) |
NM |
|
Income tax (expense)
benefit |
|
(12.0 |
) |
|
|
(2.0 |
) |
|
|
(10.0 |
) |
|
NM |
|
|
|
(122.0 |
) |
|
|
(23.5 |
) |
|
|
(98.5 |
) |
NM |
|
Net income (loss) |
|
279.3 |
|
|
|
288.0 |
|
|
|
(8.7 |
) |
|
|
(3 |
%) |
|
|
1,135.5 |
|
|
|
671.3 |
|
|
|
464.2 |
|
|
69 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
86.2 |
|
|
|
105.8 |
|
|
|
(19.6 |
) |
|
|
(19 |
%) |
|
|
258.0 |
|
|
|
286.5 |
|
|
|
(28.5 |
) |
|
(10 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
193.1 |
|
|
|
182.2 |
|
|
|
10.9 |
|
|
|
6 |
% |
|
|
877.5 |
|
|
|
384.8 |
|
|
|
492.7 |
|
|
128 |
% |
Premium on repurchase of
noncontrolling interests, net of tax |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
53.1 |
|
|
|
— |
|
|
|
53.1 |
|
|
100 |
% |
Dividends on Series A
Preferred Stock |
|
— |
|
|
|
21.8 |
|
|
|
(21.8 |
) |
|
|
(100 |
%) |
|
|
30.0 |
|
|
|
65.5 |
|
|
|
(35.5 |
) |
|
(54 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
215.5 |
|
|
|
— |
|
|
|
215.5 |
|
|
100 |
% |
Net income (loss) attributable
to common shareholders |
$ |
193.1 |
|
|
$ |
160.4 |
|
|
$ |
32.7 |
|
|
|
20 |
% |
|
$ |
578.9 |
|
|
$ |
319.3 |
|
|
$ |
259.6 |
|
|
81 |
% |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
768.6 |
|
|
$ |
505.9 |
|
|
$ |
262.7 |
|
|
|
52 |
% |
|
$ |
2,060.8 |
|
|
$ |
1,481.4 |
|
|
$ |
579.4 |
|
|
39 |
% |
Distributable cash flow
(1) |
|
594.9 |
|
|
|
383.9 |
|
|
|
211.0 |
|
|
|
55 |
% |
|
|
1,623.2 |
|
|
|
1,120.7 |
|
|
|
502.5 |
|
|
45 |
% |
Adjusted free cash flow
(1) |
|
290.8 |
|
|
|
297.2 |
|
|
|
(6.4 |
) |
|
|
(2 |
%) |
|
|
998.4 |
|
|
|
892.8 |
|
|
|
105.6 |
|
|
12 |
% |
__________________(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 or material.
Three Months Ended September 30, 2022 Compared to Three Months
Ended September 30, 2021
The increase in commodity sales reflects higher
natural gas and condensate prices ($867.5 million) and higher NGL
and natural gas volumes ($110.3 million), partially offset by lower
NGL prices ($132.7 million) and the unfavorable impact of hedges
($159.7 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 transportation and fractionation fees, partially offset
by lower export volumes.
The increase in product purchases and fuel
reflects higher natural gas and condensate prices and higher NGL
and natural gas volumes, partially offset by lower NGL prices.
The increase in operating expenses is due to
higher compensation and benefits, maintenance and rental costs
primarily due to increased activity, 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 shortening of depreciable lives of
certain assets that have been, or will be, idled, partially offset
by a lower depreciable base associated with assets that were
impaired during the fourth quarter of 2021.
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
primarily due to higher net borrowings, partially offset by higher
capitalized interest resulting from higher growth capital
investments.
The decrease in equity earnings is primarily due
to the sale of Targa GCX Pipeline LLC to a third party (the “GCX
Sale”), partially offset by lower losses resulting from the
purchase of the Company’s remaining interests in the two operated
joint ventures in South Texas that the Company previously held as
investments in unconsolidated affiliates.
The increase in income tax expense is primarily
due to a lower return-to-provision benefit in 2022 compared to
2021.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the repurchase of
the Company's development company joint ventures in January 2022
(the "DevCo JV Repurchase"), partially offset by accretion of
noncontrolling interests in certain joint ventures in WestTX and
higher income allocated to noncontrolling interest holders in the
Grand Prix Joint Venture.
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 during 2022.
Nine Months Ended September 30, 2022 Compared to Nine Months
Ended September 30, 2021
The increase in commodity sales reflects higher
NGL, natural gas and condensate prices ($4,224.4 million) and
higher NGL and natural gas volumes ($611.7 million), partially
offset by the unfavorable impact of hedges ($414.1 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, transportation and fractionation fees and export
volumes.
The increase in product purchases and fuel
reflects higher NGL, natural gas and condensate prices and higher
NGL and natural gas volumes.
The increase in operating expenses is due to
higher maintenance, compensation and benefits, and rental costs
primarily due to increased activity, system expansions, the
acquisition of certain assets in the Delaware Basin and South Texas
and inflation, partially offset by the impact of a major winter
storm that affected regions across Texas, New Mexico, Oklahoma and
Louisiana during the first quarter of 2021.
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
South Texas and the Delaware Basin, shortening of the depreciable
lives of certain assets that have been, or will be, idled and
impact of system expansions on the Company’s asset base, partially
offset by a lower depreciable base associated with assets that were
impaired during the fourth quarter of 2021.
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
primarily due to higher net borrowings and higher non-cash interest
expense related to an increase in the mandatorily redeemable
preferred interest liability, partially offset by change in fair
value of the mandatorily redeemable preferred interest, higher
capitalized interest resulting from higher growth capital
investments and lower commitment fees.
The decrease in equity earnings is primarily due
to the GCX Sale and lower earnings from the Company's investment in
Little Missouri 4 LLC, partially offset by lower losses resulting
from the purchase of the Company's remaining interests in the two
operated joint ventures in South Texas that Targa previously held
as investments in unconsolidated affiliates and lower losses from
Gulf Coast Fractionators.
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 the 5.375% Senior Notes due 2027 and the
5.875% Senior Notes due 2026. These transactions resulted in a net
loss from financing activities. During 2021, the Partnership
redeemed its 5.125% Senior Notes due 2025 and the 4.250% Senior
Notes due 2023. In addition, Targa Pipeline Partners LP redeemed
its 4.750% Senior Notes due 2021 and the 5.875% Senior Notes due
2023. 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, partially offset by a
larger release of the valuation allowance in 2022 compared to
2021.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the DevCo JV
Repurchase, partially offset by accretion of noncontrolling
interests in certain joint ventures in WestTX and higher income
allocated to noncontrolling interests holders in the Grand Prix
Joint Venture, Centrahoma Processing, LLC, Carnero Joint Venture
and Venice Energy Services, L.L.C.
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 during
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, |
|
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
564.6 |
|
|
$ |
361.4 |
|
|
$ |
203.2 |
|
|
56 |
% |
|
$ |
1,437.0 |
|
|
$ |
938.2 |
|
|
$ |
498.8 |
|
|
53 |
% |
Operating expenses |
|
176.6 |
|
|
|
122.8 |
|
|
|
53.8 |
|
|
44 |
% |
|
|
434.5 |
|
|
|
343.1 |
|
|
|
91.4 |
|
|
27 |
% |
Adjusted operating margin |
$ |
741.2 |
|
|
$ |
484.2 |
|
|
$ |
257.0 |
|
|
53 |
% |
|
$ |
1,871.5 |
|
|
$ |
1,281.3 |
|
|
$ |
590.2 |
|
|
46 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
2,307.2 |
|
|
|
2,044.7 |
|
|
|
262.5 |
|
|
13 |
% |
|
|
2,172.3 |
|
|
|
1,878.9 |
|
|
|
293.4 |
|
|
16 |
% |
Permian Delaware (5) |
|
1,784.8 |
|
|
|
842.7 |
|
|
|
942.1 |
|
|
112 |
% |
|
|
1,254.6 |
|
|
|
805.9 |
|
|
|
448.7 |
|
|
56 |
% |
Total Permian |
|
4,092.0 |
|
|
|
2,887.4 |
|
|
|
1,204.6 |
|
|
|
|
|
|
3,426.9 |
|
|
|
2,684.8 |
|
|
|
742.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
335.5 |
|
|
|
180.5 |
|
|
|
155.0 |
|
|
86 |
% |
|
|
256.9 |
|
|
|
184.0 |
|
|
|
72.9 |
|
|
40 |
% |
North Texas |
|
177.7 |
|
|
|
180.7 |
|
|
|
(3.0 |
) |
|
(2 |
%) |
|
|
176.1 |
|
|
|
179.2 |
|
|
|
(3.1 |
) |
|
(2 |
%) |
SouthOK (6) |
|
400.4 |
|
|
|
420.6 |
|
|
|
(20.2 |
) |
|
(5 |
%) |
|
|
422.7 |
|
|
|
402.6 |
|
|
|
20.1 |
|
|
5 |
% |
WestOK |
|
212.8 |
|
|
|
219.4 |
|
|
|
(6.6 |
) |
|
(3 |
%) |
|
|
209.1 |
|
|
|
211.6 |
|
|
|
(2.5 |
) |
|
(1 |
%) |
Total Central |
|
1,126.4 |
|
|
|
1,001.2 |
|
|
|
125.2 |
|
|
|
|
|
|
1,064.8 |
|
|
|
977.4 |
|
|
|
87.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) (7) |
|
144.8 |
|
|
|
135.2 |
|
|
|
9.6 |
|
|
7 |
% |
|
|
133.1 |
|
|
|
137.8 |
|
|
|
(4.7 |
) |
|
(3 |
%) |
Total Field |
|
5,363.2 |
|
|
|
4,023.8 |
|
|
|
1,339.4 |
|
|
|
|
|
|
4,624.8 |
|
|
|
3,800.0 |
|
|
|
824.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
539.1 |
|
|
|
527.1 |
|
|
|
12.0 |
|
|
2 |
% |
|
|
564.7 |
|
|
|
598.3 |
|
|
|
(33.6 |
) |
|
(6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
5,902.3 |
|
|
|
4,550.9 |
|
|
|
1,351.4 |
|
|
30 |
% |
|
|
5,189.5 |
|
|
|
4,398.3 |
|
|
|
791.2 |
|
|
18 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
332.6 |
|
|
|
293.8 |
|
|
|
38.8 |
|
|
13 |
% |
|
|
314.8 |
|
|
|
270.3 |
|
|
|
44.5 |
|
|
16 |
% |
Permian Delaware (5) |
|
219.2 |
|
|
|
119.8 |
|
|
|
99.4 |
|
|
83 |
% |
|
|
161.8 |
|
|
|
109.3 |
|
|
|
52.5 |
|
|
48 |
% |
Total Permian |
|
551.8 |
|
|
|
413.6 |
|
|
|
138.2 |
|
|
|
|
|
|
476.6 |
|
|
|
379.6 |
|
|
|
97.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
36.4 |
|
|
|
24.2 |
|
|
|
12.2 |
|
|
50 |
% |
|
|
30.1 |
|
|
|
22.6 |
|
|
|
7.5 |
|
|
33 |
% |
North Texas |
|
20.5 |
|
|
|
21.0 |
|
|
|
(0.5 |
) |
|
(2 |
%) |
|
|
19.8 |
|
|
|
20.2 |
|
|
|
(0.4 |
) |
|
(2 |
%) |
SouthOK (6) |
|
48.1 |
|
|
|
52.1 |
|
|
|
(4.0 |
) |
|
(8 |
%) |
|
|
51.4 |
|
|
|
48.8 |
|
|
|
2.6 |
|
|
5 |
% |
WestOK |
|
14.8 |
|
|
|
15.7 |
|
|
|
(0.9 |
) |
|
(6 |
%) |
|
|
15.4 |
|
|
|
16.2 |
|
|
|
(0.8 |
) |
|
(5 |
%) |
Total Central |
|
119.8 |
|
|
|
113.0 |
|
|
|
6.8 |
|
|
|
|
|
|
116.7 |
|
|
|
107.8 |
|
|
|
8.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
18.0 |
|
|
|
16.2 |
|
|
|
1.8 |
|
|
11 |
% |
|
|
15.8 |
|
|
|
16.0 |
|
|
|
(0.2 |
) |
|
(1 |
%) |
Total Field |
|
689.6 |
|
|
|
542.8 |
|
|
|
146.8 |
|
|
|
|
|
|
609.1 |
|
|
|
503.4 |
|
|
|
105.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
31.7 |
|
|
|
28.0 |
|
|
|
3.7 |
|
|
13 |
% |
|
|
35.1 |
|
|
|
34.5 |
|
|
|
0.6 |
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
721.3 |
|
|
|
570.8 |
|
|
|
150.5 |
|
|
26 |
% |
|
|
644.2 |
|
|
|
537.9 |
|
|
|
106.3 |
|
|
20 |
% |
Crude oil, Badlands,
MBbl/d |
|
122.2 |
|
|
|
140.8 |
|
|
|
(18.6 |
) |
|
(13 |
%) |
|
|
118.9 |
|
|
|
138.7 |
|
|
|
(19.8 |
) |
|
(14 |
%) |
Crude oil, Permian,
MBbl/d |
|
30.3 |
|
|
|
34.1 |
|
|
|
(3.8 |
) |
|
(11 |
%) |
|
|
29.9 |
|
|
|
35.3 |
|
|
|
(5.4 |
) |
|
(15 |
%) |
Natural gas sales, BBtu/d
(3) |
|
2,458.1 |
|
|
|
2,319.9 |
|
|
|
138.2 |
|
|
6 |
% |
|
|
2,288.4 |
|
|
|
2,162.5 |
|
|
|
125.9 |
|
|
6 |
% |
NGL sales, MBbl/d (3) |
|
436.1 |
|
|
|
412.6 |
|
|
|
23.5 |
|
|
6 |
% |
|
|
433.8 |
|
|
|
384.7 |
|
|
|
49.1 |
|
|
13 |
% |
Condensate sales, MBbl/d |
|
15.5 |
|
|
|
15.4 |
|
|
|
0.1 |
|
|
1 |
% |
|
|
15.2 |
|
|
|
15.3 |
|
|
|
(0.1 |
) |
|
(1 |
%) |
Average realized
prices - inclusive of hedges (8): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
6.71 |
|
|
|
3.51 |
|
|
|
3.20 |
|
|
91 |
% |
|
|
5.71 |
|
|
|
2.85 |
|
|
|
2.86 |
|
|
100 |
% |
NGL, $/gal |
|
0.77 |
|
|
|
0.69 |
|
|
|
0.08 |
|
|
12 |
% |
|
|
0.82 |
|
|
|
0.56 |
|
|
|
0.26 |
|
|
46 |
% |
Condensate, $/Bbl |
|
96.41 |
|
|
|
64.41 |
|
|
|
32.00 |
|
|
50 |
% |
|
|
92.25 |
|
|
|
56.86 |
|
|
|
35.39 |
|
|
62 |
% |
__________________(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 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 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.
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, 2022 |
|
|
Three Months Ended September 30, 2021 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
20.3 |
|
|
$ |
(3.58 |
) |
|
$ |
(72.7 |
) |
|
|
20.5 |
|
|
$ |
(1.52 |
) |
|
$ |
(31.2 |
) |
NGL (MMgal) |
|
|
194.9 |
|
|
|
(0.25 |
) |
|
|
(49.4 |
) |
|
|
150.4 |
|
|
|
(0.35 |
) |
|
|
(52.4 |
) |
Crude oil (MBbl) |
|
|
0.6 |
|
|
|
(26.83 |
) |
|
|
(16.1 |
) |
|
|
0.5 |
|
|
|
(18.80 |
) |
|
|
(9.4 |
) |
|
|
|
|
|
|
|
|
$ |
(138.2 |
) |
|
|
|
|
|
|
|
$ |
(93.0 |
) |
__________________(1) The price spread is the
differential between the contracted derivative instrument pricing
and the price of the corresponding settled commodity
transaction.
|
|
Nine Months Ended September 30, 2022 |
|
|
Nine Months Ended September 30, 2021 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
54.5 |
|
|
$ |
(2.91 |
) |
|
$ |
(158.8 |
) |
|
|
56.6 |
|
|
$ |
(1.01 |
) |
|
$ |
(57.2 |
) |
NGL (MMgal) |
|
|
529.7 |
|
|
|
(0.39 |
) |
|
|
(205.2 |
) |
|
|
420.0 |
|
|
|
(0.24 |
) |
|
|
(99.3 |
) |
Crude oil (MBbl) |
|
|
1.6 |
|
|
|
(38.31 |
) |
|
|
(61.3 |
) |
|
|
1.6 |
|
|
|
(11.38 |
) |
|
|
(18.2 |
) |
|
|
|
|
|
|
|
|
$ |
(425.3 |
) |
|
|
|
|
|
|
|
$ |
(174.7 |
) |
__________________(1) The price spread is the
differential between the contracted derivative instrument pricing
and the price of the corresponding settled commodity
transaction.
Three Months Ended September 30, 2022 Compared
to Three Months Ended September 30, 2021
The increase in adjusted operating margin was
due to higher natural gas inlet volumes, higher realized commodity
prices and higher fees resulting in increased margin predominantly
in the Permian. The increase in natural gas inlet volumes in the
Permian was attributable to both the acquisition of certain assets
in the Delaware Basin and increased producer activity supported by
the addition of the Legacy Plant during the third quarter of 2022.
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
volumes in the Badlands and the Coastal region was attributable to
increased producer activity.
The increase in operating expenses was
predominantly due to the acquisition of certain assets in South
Texas and the Delaware Basin in the second and third quarters of
2022. Additionally, higher volumes in the Permian, the addition of
the Legacy plant in the third quarter of 2022, a full quarter of
operations at the Heim plant in 2022 and inflation impacts resulted
in increased costs primarily in compensation and benefits, rentals,
materials, taxes and chemicals.
Nine Months Ended September 30, 2022 Compared to
Nine Months Ended September 30, 2021
The increase in adjusted operating margin was
due to higher realized commodity prices, higher natural gas inlet
volumes and higher fees resulting in increased margin predominantly
in the Permian. The increase in natural gas inlet volumes in the
Permian was attributable to both the acquisition of certain assets
in the Delaware Basin and increased producer activity supported by
the addition of the Legacy and Heim plants during the third quarter
of 2022 and 2021, respectively. Natural gas 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 decrease in volumes in the Badlands was attributable
to the impacts of winter weather, while lower volumes in the
Coastal region were due to lower producer activity.
The increase in operating expenses was
predominantly due to the acquisition of certain assets in South
Texas and the Delaware Basin in the second and third quarters of
2022. Additionally, higher volumes in the Permian, the addition of
the Legacy and Heim plants in the third quarter of 2022 and 2021,
and inflation impacts resulted in increased costs primarily in
compensation and benefits, materials, chemicals, contract labor,
rentals and taxes.
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, |
|
|
|
|
|
|
2022 |
|
2021 |
|
2022 vs. 2021 |
|
2022 |
|
|
2021 |
|
2022 vs. 2021 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
340.2 |
|
$ |
280.7 |
|
$ |
59.5 |
|
|
21 |
% |
|
$ |
1,014.6 |
|
|
$ |
920.5 |
|
$ |
94.1 |
|
10 |
% |
Operating expenses |
|
84.5 |
|
|
67.3 |
|
|
17.2 |
|
|
26 |
% |
|
|
225.8 |
|
|
|
204.1 |
|
|
21.7 |
|
11 |
% |
Adjusted operating margin |
$ |
424.7 |
|
$ |
348.0 |
|
$ |
76.7 |
|
|
22 |
% |
|
$ |
1,240.4 |
|
|
$ |
1,124.6 |
|
$ |
115.8 |
|
10 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
499.5 |
|
|
416.5 |
|
|
83.0 |
|
|
20 |
% |
|
|
484.0 |
|
|
|
383.8 |
|
|
100.2 |
|
26 |
% |
Fractionation volumes |
|
742.1 |
|
|
662.0 |
|
|
80.1 |
|
|
12 |
% |
|
|
727.5 |
|
|
|
617.5 |
|
|
110.0 |
|
18 |
% |
Export volumes (3) |
|
276.1 |
|
|
293.2 |
|
|
(17.1 |
) |
|
(6 |
%) |
|
|
319.6 |
|
|
|
305.7 |
|
|
13.9 |
|
5 |
% |
NGL sales |
|
825.0 |
|
|
792.1 |
|
|
32.9 |
|
|
4 |
% |
|
|
868.1 |
|
|
|
817.6 |
|
|
50.5 |
|
6 |
% |
__________________(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, 2022 Compared
to Three Months Ended September 30, 2021
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 primarily due to higher fuel and power costs and
lower volumes.
The increase in operating expenses was due to
higher repairs and maintenance and higher compensation and
benefits.
Nine Months Ended September 30, 2022 Compared to
Nine Months Ended September 30, 2021
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin,
partially offset by lower marketing margin. Pipeline transportation
and fractionation volumes benefited from higher supply volumes
primarily from the Company's Permian Gathering and Processing
systems and higher fees. Higher optimization margin attributable to
the winter storm resulted in higher marketing margin in 2021.
The increase in operating expenses was primarily
due to higher repairs and maintenance and higher compensation and
benefits, partially offset by lower taxes.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
(112.2 |
) |
|
$ |
13.5 |
|
|
$ |
(125.7 |
) |
|
$ |
(294.9 |
) |
|
$ |
(55.6 |
) |
|
$ |
(239.3 |
) |
Adjusted operating margin |
|
$ |
(112.2 |
) |
|
$ |
13.5 |
|
|
$ |
(125.7 |
) |
|
$ |
(294.9 |
) |
|
$ |
(55.6 |
) |
|
$ |
(239.3 |
) |
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, |
|
|
2022 |
|
|
2021 |
|
|
2022 |
|
|
2021 |
|
|
(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. |
$ |
|
193.1 |
|
|
$ |
|
182.2 |
|
|
$ |
|
877.5 |
|
|
$ |
|
384.8 |
|
Interest (income) expense, net |
|
|
125.8 |
|
|
|
|
91.0 |
|
|
|
|
300.5 |
|
|
|
|
284.2 |
|
Income tax expense (benefit) |
|
|
12.0 |
|
|
|
|
2.0 |
|
|
|
|
122.0 |
|
|
|
|
23.5 |
|
Depreciation and amortization expense |
|
|
287.2 |
|
|
|
|
222.8 |
|
|
|
|
766.2 |
|
|
|
|
650.9 |
|
(Gain) loss on sale or disposition of assets |
|
|
(6.5 |
) |
|
|
|
(1.5 |
) |
|
|
|
(8.1 |
) |
|
|
|
(1.7 |
) |
Write-down of assets |
|
|
2.7 |
|
|
|
|
0.5 |
|
|
|
|
3.7 |
|
|
|
|
5.0 |
|
(Gain) loss from financing activities (1) |
|
|
— |
|
|
|
|
— |
|
|
|
|
49.6 |
|
|
|
|
16.6 |
|
(Gain) loss from sale of equity method investment |
|
|
— |
|
|
|
|
— |
|
|
|
|
(435.9 |
) |
|
|
|
— |
|
Transaction costs related to business acquisitions (2) |
|
|
20.3 |
|
|
|
|
— |
|
|
|
|
20.3 |
|
|
|
|
— |
|
Equity (earnings) loss |
|
|
(1.7 |
) |
|
|
|
(14.3 |
) |
|
|
|
(8.7 |
) |
|
|
|
(38.9 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
|
2.4 |
|
|
|
|
28.2 |
|
|
|
|
21.7 |
|
|
|
|
88.4 |
|
Compensation on equity grants |
|
|
14.4 |
|
|
|
|
14.7 |
|
|
|
|
41.8 |
|
|
|
|
44.6 |
|
Risk management activities |
|
|
112.2 |
|
|
|
|
(12.6 |
) |
|
|
|
295.0 |
|
|
|
|
55.6 |
|
Noncontrolling interests adjustments (3) |
|
|
6.7 |
|
|
|
|
(7.1 |
) |
|
|
|
15.2 |
|
|
|
|
(31.6 |
) |
Adjusted
EBITDA |
$ |
|
768.6 |
|
|
$ |
|
505.9 |
|
|
$ |
|
2,060.8 |
|
|
$ |
|
1,481.4 |
|
Interest expense on debt obligations (4) |
|
|
(123.0 |
) |
|
|
|
(91.6 |
) |
|
|
|
(305.2 |
) |
|
|
|
(285.8 |
) |
Maintenance capital expenditures, net (5) |
|
|
(49.4 |
) |
|
|
|
(29.6 |
) |
|
|
|
(126.8 |
) |
|
|
|
(72.9 |
) |
Cash taxes |
|
|
(1.3 |
) |
|
|
|
(0.8 |
) |
|
|
|
(5.6 |
) |
|
|
|
(2.0 |
) |
Distributable Cash
Flow |
$ |
|
594.9 |
|
|
$ |
|
383.9 |
|
|
$ |
|
1,623.2 |
|
|
$ |
|
1,120.7 |
|
Growth capital expenditures, net (5) |
|
|
(304.1 |
) |
|
|
|
(86.7 |
) |
|
|
|
(624.8 |
) |
|
|
|
(227.9 |
) |
Adjusted Free Cash
Flow |
$ |
|
290.8 |
|
|
$ |
|
297.2 |
|
|
$ |
|
998.4 |
|
|
$ |
|
892.8 |
|
__________________(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) Excludes amortization of
interest expense.(5) 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 2022:
|
2022E |
|
|
(In millions) |
|
Reconciliation of Estimated Net Income attributable to
Targa Resources Corp. to |
|
|
|
Estimated Adjusted
EBITDA |
|
|
|
Net income attributable to Targa Resources Corp. |
$ |
1,245.0 |
|
Interest expense, net |
|
400.0 |
|
Income tax expense |
|
340.0 |
|
Depreciation and amortization expense |
|
1,050.0 |
|
Gain from sale of equity method investment |
|
(440.0 |
) |
Equity earnings |
|
(14.0 |
) |
Loss from financing activities (1) |
|
50.0 |
|
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
40.0 |
|
Compensation on equity grants |
|
55.0 |
|
Risk management and other |
|
180.0 |
|
Noncontrolling interests adjustments (2) |
|
(6.0 |
) |
Estimated Adjusted EBITDA |
$ |
2,900.0 |
|
(1) Losses on debt
repurchases or early debt
extinguishments.(2) Noncontrolling interest
portion of depreciation and amortization expense.
Forward-Looking Statements
Certain statements in this release are
“forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other
than statements of historical facts, included in this release that
address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future,
are forward-looking statements. These forward-looking statements
rely on a number of assumptions concerning future events and are
subject to a number of uncertainties, factors and risks, many of
which are outside the Company’s control, which could cause results
to differ materially from those expected by management of the
Company. Such risks and uncertainties include, but are not limited
to, weather, political, economic and market conditions, including a
decline in the price and market demand for natural gas, natural gas
liquids and crude oil, the 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 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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