Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported record results for the fourth quarter and
full year 2022.
Fourth Quarter and Full Year 2022
Financial Results
Fourth quarter 2022 net income (loss)
attributable to Targa Resources Corp. was $318.0 million compared
to $(313.6) million (including a non-cash pre-tax impairment loss
of $452.3 million on assets in SouthTX associated with Targa's
Central operations) for the fourth quarter of 2021. For full year
2022, net income attributable to Targa Resources Corp. was a record
$1,195.5 million compared to $71.2 million for 2021.
The Company reported record adjusted earnings
before interest, income taxes, depreciation and amortization, and
other non-cash items (“adjusted EBITDA”) of $840.4 million for the
fourth quarter of 2022 compared to $570.6 million for the fourth
quarter of 2021. For full year 2022, Targa reported record adjusted
EBITDA of $2,901.1 million compared to $2,052.0 million for the
full year 2021.
The Company reported distributable cash flow and
adjusted free cash flow for the fourth quarter of 2022 of $655.5
million and $103.1 million, respectively. For the full year 2022,
the Company reported distributable cash flow and adjusted free cash
flow of $2,278.7 million and $1,101.5 million, respectively.
On January 19, 2023, Targa declared a quarterly
dividend of $0.35 per share of its common stock for the fourth
quarter of 2022, or $1.40 per share on an annualized basis. Total
cash dividends of approximately $79 million were paid on February
15, 2023 on all outstanding shares of common stock to holders of
record as of the close of business on January 31, 2023.
Targa repurchased 395,798 shares of its common
stock during the fourth quarter of 2022 at a weighted average price
of $70.75 for a total net cost of $28.0 million. For the year ended
December 31, 2022, Targa repurchased 3,412,354 shares of its common
stock at a weighted average price of $65.87 for a total net cost of
$224.8 million. There was $143.8 million remaining under the
Company’s $500 million common share repurchase program as of
December 31, 2022.
Fourth Quarter 2022 - Sequential Quarter over Quarter
Commentary
Targa reported fourth quarter 2022 adjusted
EBITDA of $840.4 million, representing a 9 percent increase
compared to the third quarter of 2022. In the Gathering &
Processing (“G&P”) segment, lower sequential adjusted operating
margin was driven by lower commodity prices offset by higher
natural gas inlet volumes across Targa’s Permian systems and a full
quarter contribution from the Company’s Delaware Basin acquisition,
which closed with an accounting effective date of August 1, 2022.
Targa’s Permian natural gas inlet volumes averaged a record 4.7
billion cubic feet per day (“Bcf/d”) in the fourth quarter of 2022
even though volumes were negatively impacted by Winter Storm
Elliott. In the Logistics & Transportation (“L&T”) segment,
the sequential increase in segment adjusted operating margin was
attributable to higher marketing margin, higher pipeline
transportation and fractionation volumes, and higher LPG export
volumes. Marketing margin was higher due to greater optimization
opportunities. NGL pipeline transportation and fractionation
volumes achieved record levels during the fourth quarter primarily
due to higher supply volumes from Targa’s Permian G&P systems
and third parties, despite the negative impacts of Winter Storm
Elliott during the quarter. LPG export volumes were higher
sequentially due to improved export market conditions. In the
fourth quarter of 2022, lower operating expenses were attributable
to lower repairs and maintenance, while higher general and
administrative expenses were attributable to higher compensation
and benefits.
Capitalization and Liquidity
The Company’s total consolidated debt as of
December 31, 2022 was $11,536.4 million, net of $65.6 million of
debt issuance costs and $8.4 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,
$290.0 million outstanding under the TRGP Revolver, $1,008.7
million outstanding under the Commercial Paper Program, $800.0
million outstanding under the Securitization Facility, and $227.3
million of finance lease liabilities.
Total consolidated liquidity as of December 31, 2022 was
approximately $1.6 billion, including $1.4 billion available under
the TRGP Revolver and $219.0 million of cash.
Acquisition and Financing Update
In January 2023, Targa completed the acquisition
of Blackstone Energy Partners’ 25 percent interest in Targa’s Grand
Prix NGL Pipeline (“Grand Prix”) for aggregate consideration of
$1.05 billion in cash, with an effective date of January 1, 2023
(the “Grand Prix Transaction”). Following the closing of the Grand
Prix Transaction, Targa owns 100% of Grand Prix.
In January 2023, Targa completed an underwritten
public offering of (i) $900.0 million in aggregate principal amount
of its 6.125% Senior Notes due 2033 and (ii) $850.0 million in
aggregate principal amount of its 6.500% Senior Notes due 2053,
resulting in net proceeds of approximately $1.7 billion. Targa used
a portion of the net proceeds from the issuance to fund the Grand
Prix Transaction and the remaining net proceeds for general
corporate purposes, including to reduce borrowings under the TRGP
Revolver and the Commercial Paper Program.
Growth Projects Update
Construction continues on Targa’s 275 million
cubic feet per day (“MMcf/d”) Legacy II plant and 275 MMcf/d
Greenwood plant in Permian Midland, its 275 MMcf/d Midway plant and
275 MMcf/d Wildcat II plant in Permian Delaware, its 120 thousand
barrels per day (“MBbl/d”) fractionation train (“Train 9”) in Mont
Belvieu, Texas, and its Daytona NGL Pipeline. Targa remains
on-track to complete these expansions as previously disclosed.
In response to increasing production and to meet
the infrastructure needs of producers, Targa is transferring an
existing cryogenic natural gas processing plant acquired in its
April 2022 South Texas acquisition to the Permian Delaware. The
plant will be installed as a new 230 MMcf/d cryogenic natural gas
processing plant (the “Roadrunner II plant”). The Roadrunner II
plant is expected to begin operations in the second quarter of
2024.
2023 Operational, Financial, and Capital Return
Expectations
Targa’s 2023 operational and financial
expectations assume Waha natural gas prices average $2.25 per
million British Thermal Units (“MMbtu”), natural gas liquids
(“NGL”) composite barrel prices average $0.70 per gallon, and crude
oil prices average $75 per barrel. Targa estimates its 2023 average
Permian natural gas inlet volumes will increase 10 percent when
compared to its average Permian inlet volumes for the fourth
quarter of 2022, which will drive increasing volumes through its
L&T systems.
For 2023, Targa estimates full year adjusted
EBITDA to be between $3.5 billion and $3.7 billion, with the
midpoint of the range representing a 24 percent increase over full
year 2022 adjusted EBITDA. Targa’s estimate for 2023 net growth
capital expenditures is between $1.8 billion to $1.9 billion, based
on announced projects and other identified spending. Net
maintenance capital expenditures for 2023 are estimated to be
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.
Targa expects to recommend a 43 percent
year-over-year increase to its annualized common stock dividend per
share for 2023 to $2.00 per share. The increased dividend will be
recommended to Targa’s Board of Directors in April for the first
quarter of 2023, with payment to shareholders in May 2023. Targa
also expects to remain in position to continue to execute
opportunistically under its existing $500 million common share
repurchase program and currently plans on recommending that the
Board of Directors authorize a new $1 billion share repurchase
program as the Company gets closer to exhausting available capacity
under the existing program.
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 February 22, 2023 to discuss its fourth 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/5awdkn55. 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 December 31, |
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
4,075.3 |
|
|
$ |
5,025.1 |
|
|
$ |
(949.8 |
) |
|
|
(19 |
%) |
|
$ |
19,066.0 |
|
|
$ |
15,602.5 |
|
|
$ |
3,463.5 |
|
|
22 |
% |
Fees from midstream services |
|
479.4 |
|
|
|
416.5 |
|
|
|
62.9 |
|
|
|
15 |
% |
|
|
1,863.8 |
|
|
|
1,347.3 |
|
|
|
516.5 |
|
|
38 |
% |
Total revenues |
|
4,554.7 |
|
|
|
5,441.6 |
|
|
|
(886.9 |
) |
|
|
(16 |
%) |
|
|
20,929.8 |
|
|
|
16,949.8 |
|
|
|
3,980.0 |
|
|
23 |
% |
Product purchases and
fuel |
|
3,324.2 |
|
|
|
4,569.7 |
|
|
|
(1,245.5 |
) |
|
|
(27 |
%) |
|
|
16,882.1 |
|
|
|
13,729.5 |
|
|
|
3,152.6 |
|
|
23 |
% |
Operating expenses |
|
252.2 |
|
|
|
201.7 |
|
|
|
50.5 |
|
|
|
25 |
% |
|
|
912.8 |
|
|
|
747.0 |
|
|
|
165.8 |
|
|
22 |
% |
Depreciation and amortization
expense |
|
329.8 |
|
|
|
219.7 |
|
|
|
110.1 |
|
|
|
50 |
% |
|
|
1,096.0 |
|
|
|
870.6 |
|
|
|
225.4 |
|
|
26 |
% |
General and administrative
expense |
|
92.5 |
|
|
|
80.7 |
|
|
|
11.8 |
|
|
|
15 |
% |
|
|
309.7 |
|
|
|
273.2 |
|
|
|
36.5 |
|
|
13 |
% |
Impairment of long-lived
assets |
|
— |
|
|
|
452.3 |
|
|
|
(452.3 |
) |
|
|
(100 |
%) |
|
|
— |
|
|
|
452.3 |
|
|
|
(452.3 |
) |
|
(100 |
%) |
Other operating (income)
expense |
|
4.7 |
|
|
|
9.0 |
|
|
|
(4.3 |
) |
|
|
(48 |
%) |
|
|
0.2 |
|
|
|
12.4 |
|
|
|
(12.2 |
) |
|
(98 |
%) |
Income (loss) from
operations |
|
551.3 |
|
|
|
(91.5 |
) |
|
|
642.8 |
|
|
NM |
|
|
|
1,729.0 |
|
|
|
864.8 |
|
|
|
864.2 |
|
|
100 |
% |
Interest expense, net |
|
(145.6 |
) |
|
|
(103.7 |
) |
|
|
(41.9 |
) |
|
|
40 |
% |
|
|
(446.1 |
) |
|
|
(387.9 |
) |
|
|
(58.2 |
) |
|
15 |
% |
Equity earnings (loss) |
|
0.3 |
|
|
|
(62.8 |
) |
|
|
63.1 |
|
|
|
100 |
% |
|
|
9.1 |
|
|
|
(23.9 |
) |
|
|
33.0 |
|
|
138 |
% |
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 |
|
(0.3 |
) |
|
|
0.1 |
|
|
|
(0.4 |
) |
|
NM |
|
|
|
(15.1 |
) |
|
|
0.5 |
|
|
|
(15.6 |
) |
NM |
|
Income tax (expense)
benefit |
|
(9.8 |
) |
|
|
8.7 |
|
|
|
(18.5 |
) |
|
|
(213 |
%) |
|
|
(131.8 |
) |
|
|
(14.8 |
) |
|
|
(117.0 |
) |
NM |
|
Net income (loss) |
|
395.9 |
|
|
|
(249.2 |
) |
|
|
645.1 |
|
|
|
259 |
% |
|
|
1,531.4 |
|
|
|
422.1 |
|
|
|
1,109.3 |
|
|
263 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
77.9 |
|
|
|
64.4 |
|
|
|
13.5 |
|
|
|
21 |
% |
|
|
335.9 |
|
|
|
350.9 |
|
|
|
(15.0 |
) |
|
(4 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
318.0 |
|
|
|
(313.6 |
) |
|
|
631.6 |
|
|
|
201 |
% |
|
|
1,195.5 |
|
|
|
71.2 |
|
|
|
1,124.3 |
|
NM |
|
Premium on repurchase of
noncontrolling interests, net of tax |
|
0.1 |
|
|
|
— |
|
|
|
0.1 |
|
|
|
— |
|
|
|
53.2 |
|
|
|
— |
|
|
|
53.2 |
|
|
100 |
% |
Dividends on Series A
Preferred Stock |
|
— |
|
|
|
21.8 |
|
|
|
(21.8 |
) |
|
|
(100 |
%) |
|
|
30.0 |
|
|
|
87.3 |
|
|
|
(57.3 |
) |
|
(66 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
215.5 |
|
|
|
— |
|
|
|
215.5 |
|
|
100 |
% |
Net income (loss) attributable
to common shareholders |
$ |
317.9 |
|
|
$ |
(335.4 |
) |
|
$ |
653.3 |
|
|
|
195 |
% |
|
$ |
896.8 |
|
|
$ |
(16.1 |
) |
|
$ |
912.9 |
|
NM |
|
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
840.4 |
|
|
$ |
570.6 |
|
|
$ |
269.8 |
|
|
|
47 |
% |
|
$ |
2,901.1 |
|
|
$ |
2,052.0 |
|
|
$ |
849.1 |
|
|
41 |
% |
Distributable cash flow
(1) |
|
655.5 |
|
|
|
420.7 |
|
|
|
234.8 |
|
|
|
56 |
% |
|
|
2,278.7 |
|
|
|
1,541.4 |
|
|
|
737.3 |
|
|
48 |
% |
Adjusted free cash flow
(1) |
|
103.1 |
|
|
|
240.8 |
|
|
|
(137.7 |
) |
|
|
(57 |
%) |
|
|
1,101.5 |
|
|
|
1,133.7 |
|
|
|
(32.2 |
) |
|
(3 |
%) |
(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 December 31, 2022 Compared to Three Months
Ended December 31, 2021
The decrease in commodity sales reflects lower
NGL prices ($1,146.7 million) and NGL and natural gas volumes
($64.8 million), partially offset by higher natural gas prices
($89.6 million) and condensate volumes ($15.8 million), and the
favorable impact of hedges ($150.0 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 volumes, partially
offset by lower export fees.
The decrease in product purchases and fuel
reflects lower NGL prices and NGL and natural gas volumes,
partially offset by higher natural gas prices and condensate
volumes.
The increase in operating expenses is primarily
due to increased activity and system expansions, the acquisition of
certain assets in South Texas and the Delaware Basin, and
inflation.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the acquisition of certain assets in
the Delaware Basin and the 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, and
insurance costs.
In 2021, the Company recognized a non-cash
pre-tax impairment loss of $452.3 million on assets in the South
Texas region associated with the Company's Central operations.
The increase in interest expense, net is
primarily due to higher net borrowings, partially offset by change
in fair value of the mandatorily redeemable preferred interests and
higher capitalized interest resulting from higher growth capital
investments.
The increase in equity earnings is primarily due
to lower losses resulting from the purchase of the Company's
remaining interests in the two joint ventures in South Texas that
the Company previously held as investments in unconsolidated
affiliates, partially offset by lower earnings resulting from the
impact of the GCX Sale.
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 impact of statutory rate changes in Oklahoma and Louisiana in
2021 and the correction of a state tax error in 2021.
The increase in net income (loss) attributable
to noncontrolling interests is primarily due to impairment losses
in 2021 allocated to noncontrolling interest holders in the Carnero
Joint Venture, partially offset by the repurchase of the Company's
development company joint ventures in January 2022 (the “DevCo JV
Repurchase”).
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.
Year Ended December 31, 2022 Compared to Year Ended December 31,
2021
The increase in commodity sales reflects higher
natural gas, NGL and condensate prices ($3,116.3 million) and
higher NGL, natural gas and condensate volumes ($615.9 million),
partially offset by the unfavorable impact of hedges ($264.1
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, and transportation and fractionation volumes, partially
offset by lower export fees.
The increase in product purchases and fuel
reflects higher natural gas, NGL and condensate prices and 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 South Texas and the Delaware Basin, 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
the Delaware Basin and South Texas, the shortening of depreciable
lives of certain assets that have been, or will be, idled and the
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.
In 2021, the Company recognized a non-cash
pre-tax impairment loss of $452.3 million on assets in the South
Texas region associated with the Company's Central operations.
Other operating (income) expense in 2021
consisted primarily of the write-down of certain assets to their
recoverable amounts.
The increase in interest expense, net is
primarily due to higher net borrowings, partially offset by the
change in fair value of the mandatorily redeemable preferred
interests, higher capitalized interest resulting from higher growth
capital investments, and lower commitment fees.
The increase in equity earnings is primarily due
to lower losses resulting from the purchase of the Company's
remaining interests in the two joint ventures in South Texas that
the Company previously held as investments in unconsolidated
affiliates and lower losses from Gulf Coast Fractionators,
partially offset by lower earnings resulting from the impact of the
GCX Sale and lower earnings from the Company's investment in Little
Missouri 4 LLC.
During 2022, the Partnership redeemed the 5.375%
Senior Notes due 2027 and the 5.875% Senior Notes due 2026. In
addition, the Company terminated the previous TRGP senior secured
revolving credit facility (the “Previous TRGP Revolver”) and the
Partnership's senior secured revolving credit facility (the
“Partnership Revolver”). These transactions resulted in a net loss
from financing activities. During 2021, the Partnership redeemed
the 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due
2023 and Targa Pipeline Partners LP redeemed its TPL 4.750% Senior
Notes due 2021 and TPL 5.875% Senior Notes due 2023, resulting 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 impact of statutory rate changes in Oklahoma and Louisiana in
2021 and the correction of a state tax error in 2021.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the DevCo JV
Repurchase, partially offset by impairment losses in 2021 allocated
to noncontrolling interest holders in the Carnero Joint Venture,
higher income allocation to noncontrolling interests holders in the
Grand Prix Joint Venture and Centrahoma Processing, LLC., and an
increase in noncontrolling interest for a joint venture partner in
WestTX.
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 December 31, |
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
|
544.0 |
|
|
$ |
|
387.1 |
|
|
$ |
|
156.9 |
|
|
|
41 |
% |
|
$ |
|
1,981.0 |
|
|
$ |
|
1,325.3 |
|
|
$ |
|
655.7 |
|
|
|
49 |
% |
Operating expenses |
|
|
177.3 |
|
|
|
|
133.1 |
|
|
|
|
44.2 |
|
|
|
33 |
% |
|
|
|
611.8 |
|
|
|
|
476.2 |
|
|
|
|
135.6 |
|
|
|
28 |
% |
Adjusted operating margin |
$ |
|
721.3 |
|
|
$ |
|
520.2 |
|
|
$ |
|
201.1 |
|
|
|
39 |
% |
|
$ |
|
2,592.8 |
|
|
$ |
|
1,801.5 |
|
|
$ |
|
791.3 |
|
|
|
44 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
2,376.0 |
|
|
|
|
2,075.4 |
|
|
|
|
300.6 |
|
|
|
14 |
% |
|
|
|
2,223.6 |
|
|
|
|
1,928.4 |
|
|
|
|
295.2 |
|
|
|
15 |
% |
Permian Delaware (5) |
|
|
2,371.3 |
|
|
|
|
940.5 |
|
|
|
|
1,430.8 |
|
|
|
152 |
% |
|
|
|
1,536.1 |
|
|
|
|
839.8 |
|
|
|
|
696.3 |
|
|
|
83 |
% |
Total Permian |
|
|
4,747.3 |
|
|
|
|
3,015.9 |
|
|
|
|
1,731.4 |
|
|
|
|
|
|
|
3,759.7 |
|
|
|
|
2,768.2 |
|
|
|
|
991.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
|
334.7 |
|
|
|
|
159.2 |
|
|
|
|
175.5 |
|
|
|
110 |
% |
|
|
|
276.5 |
|
|
|
|
177.7 |
|
|
|
|
98.8 |
|
|
|
56 |
% |
North Texas |
|
|
219.4 |
|
|
|
|
178.2 |
|
|
|
|
41.2 |
|
|
|
23 |
% |
|
|
|
187.0 |
|
|
|
|
178.9 |
|
|
|
|
8.1 |
|
|
|
5 |
% |
SouthOK (6) |
|
|
359.7 |
|
|
|
|
415.9 |
|
|
|
|
(56.2 |
) |
|
|
(14 |
%) |
|
|
|
406.8 |
|
|
|
|
405.9 |
|
|
|
|
0.9 |
|
|
|
— |
|
WestOK |
|
|
207.3 |
|
|
|
|
215.5 |
|
|
|
|
(8.2 |
) |
|
|
(4 |
%) |
|
|
|
208.7 |
|
|
|
|
212.6 |
|
|
|
|
(3.9 |
) |
|
|
(2 |
%) |
Total Central |
|
|
1,121.1 |
|
|
|
|
968.8 |
|
|
|
|
152.3 |
|
|
|
|
|
|
|
1,079.0 |
|
|
|
|
975.1 |
|
|
|
|
103.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) (7) |
|
|
140.2 |
|
|
|
|
145.9 |
|
|
|
|
(5.7 |
) |
|
|
(4 |
%) |
|
|
|
134.9 |
|
|
|
|
139.8 |
|
|
|
|
(4.9 |
) |
|
|
(4 |
%) |
Total Field |
|
|
6,008.6 |
|
|
|
|
4,130.6 |
|
|
|
|
1,878.0 |
|
|
|
|
|
|
|
4,973.6 |
|
|
|
|
3,883.1 |
|
|
|
|
1,090.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
457.3 |
|
|
|
|
554.3 |
|
|
|
|
(97.0 |
) |
|
|
(17 |
%) |
|
|
|
537.6 |
|
|
|
|
587.2 |
|
|
|
|
(49.6 |
) |
|
|
(8 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
6,465.9 |
|
|
|
|
4,684.9 |
|
|
|
|
1,781.0 |
|
|
|
38 |
% |
|
|
|
5,511.2 |
|
|
|
|
4,470.3 |
|
|
|
|
1,040.9 |
|
|
|
23 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
342.0 |
|
|
|
|
300.4 |
|
|
|
|
41.6 |
|
|
|
14 |
% |
|
|
|
321.7 |
|
|
|
|
277.9 |
|
|
|
|
43.8 |
|
|
|
16 |
% |
Permian Delaware (5) |
|
|
289.0 |
|
|
|
|
128.1 |
|
|
|
|
160.9 |
|
|
|
126 |
% |
|
|
|
193.9 |
|
|
|
|
114.1 |
|
|
|
|
79.8 |
|
|
|
70 |
% |
Total Permian |
|
|
631.0 |
|
|
|
|
428.5 |
|
|
|
|
202.5 |
|
|
|
|
|
|
|
515.6 |
|
|
|
|
392.0 |
|
|
|
|
123.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
|
34.2 |
|
|
|
|
21.0 |
|
|
|
|
13.2 |
|
|
|
63 |
% |
|
|
|
31.2 |
|
|
|
|
22.2 |
|
|
|
|
9.0 |
|
|
|
41 |
% |
North Texas |
|
|
25.2 |
|
|
|
|
19.7 |
|
|
|
|
5.5 |
|
|
|
28 |
% |
|
|
|
21.2 |
|
|
|
|
20.1 |
|
|
|
|
1.1 |
|
|
|
5 |
% |
SouthOK (6) |
|
|
36.3 |
|
|
|
|
51.5 |
|
|
|
|
(15.2 |
) |
|
|
(30 |
%) |
|
|
|
47.6 |
|
|
|
|
49.5 |
|
|
|
|
(1.9 |
) |
|
|
(4 |
%) |
WestOK |
|
|
12.1 |
|
|
|
|
17.3 |
|
|
|
|
(5.2 |
) |
|
|
(30 |
%) |
|
|
|
14.6 |
|
|
|
|
16.5 |
|
|
|
|
(1.9 |
) |
|
|
(12 |
%) |
Total Central |
|
|
107.8 |
|
|
|
|
109.5 |
|
|
|
|
(1.7 |
) |
|
|
|
|
|
|
114.6 |
|
|
|
|
108.3 |
|
|
|
|
6.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
|
17.0 |
|
|
|
|
17.0 |
|
|
|
|
— |
|
|
|
— |
|
|
|
|
16.1 |
|
|
|
|
16.2 |
|
|
|
|
(0.1 |
) |
|
|
(1 |
%) |
Total Field |
|
|
755.8 |
|
|
|
|
555.0 |
|
|
|
|
200.8 |
|
|
|
|
|
|
|
646.3 |
|
|
|
|
516.5 |
|
|
|
|
129.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
22.9 |
|
|
|
|
32.2 |
|
|
|
|
(9.3 |
) |
|
|
(29 |
%) |
|
|
|
32.0 |
|
|
|
|
33.9 |
|
|
|
|
(1.9 |
) |
|
|
(6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
778.7 |
|
|
|
|
587.2 |
|
|
|
|
191.5 |
|
|
|
33 |
% |
|
|
|
678.3 |
|
|
|
|
550.4 |
|
|
|
|
127.9 |
|
|
|
23 |
% |
Crude oil, Badlands,
MBbl/d |
|
|
113.7 |
|
|
|
|
147.6 |
|
|
|
|
(33.9 |
) |
|
|
(23 |
%) |
|
|
|
117.6 |
|
|
|
|
140.9 |
|
|
|
|
(23.3 |
) |
|
|
(17 |
%) |
Crude oil, Permian,
MBbl/d |
|
|
28.4 |
|
|
|
|
34.4 |
|
|
|
|
(6.0 |
) |
|
|
(17 |
%) |
|
|
|
29.5 |
|
|
|
|
35.0 |
|
|
|
|
(5.5 |
) |
|
|
(16 |
%) |
Natural gas sales, BBtu/d
(3) |
|
|
2,416.3 |
|
|
|
|
2,341.8 |
|
|
|
|
74.5 |
|
|
|
3 |
% |
|
|
|
2,320.6 |
|
|
|
|
2,207.7 |
|
|
|
|
112.9 |
|
|
|
5 |
% |
NGL sales, MBbl/d (3) |
|
|
453.3 |
|
|
|
|
424.1 |
|
|
|
|
29.2 |
|
|
|
7 |
% |
|
|
|
438.7 |
|
|
|
|
394.6 |
|
|
|
|
44.1 |
|
|
|
11 |
% |
Condensate sales, MBbl/d |
|
|
16.3 |
|
|
|
|
13.9 |
|
|
|
|
2.4 |
|
|
|
17 |
% |
|
|
|
15.5 |
|
|
|
|
14.9 |
|
|
|
|
0.6 |
|
|
|
4 |
% |
Average realized
prices - inclusive of hedges (8): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
4.35 |
|
|
|
|
4.43 |
|
|
|
|
(0.08 |
) |
|
|
(2 |
%) |
|
|
|
5.35 |
|
|
|
|
3.27 |
|
|
|
|
2.08 |
|
|
|
64 |
% |
NGL, $/gal |
|
|
0.56 |
|
|
|
|
0.76 |
|
|
|
|
(0.20 |
) |
|
|
(26 |
%) |
|
|
|
0.75 |
|
|
|
|
0.61 |
|
|
|
|
0.14 |
|
|
|
23 |
% |
Condensate, $/Bbl |
|
|
77.21 |
|
|
|
|
70.29 |
|
|
|
|
6.92 |
|
|
|
10 |
% |
|
|
|
88.26 |
|
|
|
|
60.02 |
|
|
|
|
28.24 |
|
|
|
47 |
% |
(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 December 31, 2022 |
|
|
Three Months Ended December 31, 2021 |
|
|
|
(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) |
|
|
20.2 |
|
|
$ |
(0.02 |
) |
|
$ |
(0.4 |
) |
|
|
20.2 |
|
|
$ |
(2.51 |
) |
|
$ |
(50.8 |
) |
NGL (MMgal) |
|
|
187.9 |
|
|
|
(0.04 |
) |
|
|
(7.8 |
) |
|
|
175.8 |
|
|
|
(0.31 |
) |
|
|
(53.9 |
) |
Crude oil (MBbl) |
|
|
0.6 |
|
|
|
(14.22 |
) |
|
|
(8.5 |
) |
|
|
0.5 |
|
|
|
(23.80 |
) |
|
|
(11.9 |
) |
|
|
|
|
|
|
|
|
$ |
(16.7 |
) |
|
|
|
|
|
|
|
$ |
(116.6 |
) |
(1) The price spread is
the differential between the contracted derivative instrument
pricing and the price of the corresponding settled commodity
transaction.
|
|
Year Ended December 31, 2022 |
|
|
Year Ended December 31, 2021 |
|
|
|
(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) |
|
|
74.8 |
|
|
$ |
(2.13 |
) |
|
$ |
(159.2 |
) |
|
|
76.8 |
|
|
$ |
(1.41 |
) |
|
$ |
(108.0 |
) |
NGL (MMgal) |
|
|
717.6 |
|
|
|
(0.30 |
) |
|
|
(213.0 |
) |
|
|
581.5 |
|
|
|
(0.26 |
) |
|
|
(153.1 |
) |
Crude oil (MBbl) |
|
|
2.2 |
|
|
|
(31.73 |
) |
|
|
(69.8 |
) |
|
|
2.1 |
|
|
|
(14.33 |
) |
|
|
(30.1 |
) |
|
|
|
|
|
|
|
|
$ |
(442.0 |
) |
|
|
|
|
|
|
|
$ |
(291.2 |
) |
(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 December 31, 2022 Compared to Three
Months Ended December 31, 2021
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 NGL and natural gas 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 and Red Hills VI plants in the
Permian region during the third quarter of 2022 and increased
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. The decrease in volumes in the
Coastal region was attributable to lower production.
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 and Red Hills VI plants in the third quarter of
2022 and inflation impacts resulted in increased costs.
Year Ended December 31, 2022 Compared to Year
Ended December 31, 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 the acquisition of
certain assets in the Delaware Basin during the third quarter of
2022, higher producer activity and the addition of the Legacy and
Red Hills VI plants during the third quarter of 2022. The decrease
in volumes in the Coastal region was 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, which included one-time acquisition costs. Additionally,
higher volumes in the Permian, the addition of the Legacy and Red
Hills VI plants during the third quarter of 2022 and the Heim plant
in the third quarter of 2021, 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 December 31, |
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
|
441.6 |
|
|
$ |
|
343.5 |
|
|
$ |
|
98.1 |
|
|
29 |
% |
|
$ |
|
1,456.3 |
|
|
$ |
|
1,264.3 |
|
|
$ |
|
192.0 |
|
|
15 |
% |
Operating expenses |
|
|
74.4 |
|
|
|
|
69.2 |
|
|
|
|
5.2 |
|
|
8 |
% |
|
|
|
300.2 |
|
|
|
|
273.0 |
|
|
|
|
27.2 |
|
|
10 |
% |
Adjusted operating margin |
$ |
|
516.0 |
|
|
$ |
|
412.7 |
|
|
$ |
|
103.3 |
|
|
25 |
% |
|
$ |
|
1,756.5 |
|
|
$ |
|
1,537.3 |
|
|
$ |
|
219.2 |
|
|
14 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
|
502.3 |
|
|
|
|
432.8 |
|
|
|
|
69.5 |
|
|
16 |
% |
|
|
|
488.6 |
|
|
|
|
396.2 |
|
|
|
|
92.4 |
|
|
23 |
% |
Fractionation volumes |
|
|
744.4 |
|
|
|
|
611.6 |
|
|
|
|
132.8 |
|
|
22 |
% |
|
|
|
731.7 |
|
|
|
|
616.0 |
|
|
|
|
115.7 |
|
|
19 |
% |
Export volumes (3) |
|
|
299.4 |
|
|
|
|
350.3 |
|
|
|
|
(50.9 |
) |
|
(15 |
%) |
|
|
|
314.5 |
|
|
|
|
316.9 |
|
|
|
|
(2.4 |
) |
|
(1 |
%) |
NGL sales |
|
|
861.0 |
|
|
|
|
886.3 |
|
|
|
|
(25.3 |
) |
|
(3 |
%) |
|
|
|
866.3 |
|
|
|
|
834.9 |
|
|
|
|
31.4 |
|
|
4 |
% |
(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 December 31, 2022 Compared
to Three Months Ended December 31, 2021
The increase in adjusted operating margin was
due to higher marketing margin and higher pipeline transportation
and fractionation margin, partially offset by lower 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 decreased primarily due to lower volumes.
The increase in operating expenses was due to
higher compensation and benefits, higher taxes and higher repairs
and maintenance.
Year Ended December 31, 2022 Compared to Year
Ended December 31, 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.
The increase in operating expenses was primarily
due to higher repairs and maintenance.
Other
|
|
Three Months Ended December 31, |
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
(7.5 |
) |
|
$ |
(60.3 |
) |
|
$ |
52.8 |
|
|
$ |
(302.4 |
) |
|
$ |
(115.9 |
) |
|
$ |
(186.5 |
) |
Adjusted operating margin |
|
$ |
(7.5 |
) |
|
$ |
(60.3 |
) |
|
$ |
52.8 |
|
|
$ |
(302.4 |
) |
|
$ |
(115.9 |
) |
|
$ |
(186.5 |
) |
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 December 31, |
|
|
|
Year Ended December 31, |
|
|
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. |
$ |
|
318.0 |
|
|
$ |
|
(313.6 |
) |
|
$ |
|
1,195.5 |
|
|
$ |
|
71.2 |
|
Interest (income) expense, net |
|
|
145.6 |
|
|
|
|
103.7 |
|
|
|
|
446.1 |
|
|
|
|
387.9 |
|
Income tax expense (benefit) |
|
|
9.8 |
|
|
|
|
(8.7 |
) |
|
|
|
131.8 |
|
|
|
|
14.8 |
|
Depreciation and amortization expense |
|
|
329.8 |
|
|
|
|
219.7 |
|
|
|
|
1,096.0 |
|
|
|
|
870.6 |
|
Impairment of long-lived assets |
|
|
— |
|
|
|
|
452.3 |
|
|
|
|
— |
|
|
|
|
452.3 |
|
(Gain) loss on sale or disposition of assets |
|
|
(1.5 |
) |
|
|
|
3.7 |
|
|
|
|
(9.6 |
) |
|
|
|
2.0 |
|
Write-down of assets |
|
|
6.2 |
|
|
|
|
5.3 |
|
|
|
|
9.8 |
|
|
|
|
10.3 |
|
(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 acquisition (2) |
|
|
3.6 |
|
|
|
|
— |
|
|
|
|
23.9 |
|
|
|
|
— |
|
Equity (earnings) loss |
|
|
(0.3 |
) |
|
|
|
62.8 |
|
|
|
|
(9.1 |
) |
|
|
|
23.9 |
|
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
|
5.5 |
|
|
|
|
28.1 |
|
|
|
|
27.2 |
|
|
|
|
116.5 |
|
Change in contingent considerations |
|
|
— |
|
|
|
|
0.1 |
|
|
|
|
— |
|
|
|
|
0.1 |
|
Compensation on equity grants |
|
|
15.7 |
|
|
|
|
14.6 |
|
|
|
|
57.5 |
|
|
|
|
59.2 |
|
Risk management activities |
|
|
7.5 |
|
|
|
|
60.4 |
|
|
|
|
302.5 |
|
|
|
|
116.0 |
|
Noncontrolling interests adjustments (3) |
|
|
0.5 |
|
|
|
|
(57.8 |
) |
|
|
|
15.8 |
|
|
|
|
(89.4 |
) |
Adjusted
EBITDA |
$ |
|
840.4 |
|
|
$ |
|
570.6 |
|
|
$ |
|
2,901.1 |
|
|
$ |
|
2,052.0 |
|
Interest expense on debt obligations (4) |
|
|
(142.5 |
) |
|
|
|
(90.4 |
) |
|
|
|
(447.6 |
) |
|
|
|
(376.2 |
) |
Maintenance capital expenditures, net (5) |
|
|
(41.3 |
) |
|
|
|
(58.8 |
) |
|
|
|
(168.1 |
) |
|
|
|
(131.7 |
) |
Cash taxes |
|
|
(1.1 |
) |
|
|
|
(0.7 |
) |
|
|
|
(6.7 |
) |
|
|
|
(2.7 |
) |
Distributable Cash
Flow |
$ |
|
655.5 |
|
|
$ |
|
420.7 |
|
|
$ |
|
2,278.7 |
|
|
$ |
|
1,541.4 |
|
Growth capital expenditures, net (5) |
|
|
(552.4 |
) |
|
|
|
(179.9 |
) |
|
|
|
(1,177.2 |
) |
|
|
|
(407.7 |
) |
Adjusted Free Cash
Flow |
$ |
|
103.1 |
|
|
$ |
|
240.8 |
|
|
$ |
|
1,101.5 |
|
|
$ |
|
1,133.7 |
|
(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 (including the effects of
the impairment of long-lived assets on non-controlling
interests).(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 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. |
$ |
1,230.0 |
|
|
Interest expense, net |
|
710.0 |
|
|
Income tax expense |
|
350.0 |
|
|
Depreciation and amortization expense |
|
1,260.0 |
|
|
Equity earnings |
|
(20.0 |
) |
|
Distributions from unconsolidated affiliates |
|
25.0 |
|
|
Compensation on equity grants |
|
60.0 |
|
|
Risk management and other |
|
– |
|
|
Noncontrolling interests adjustments (1) |
|
(15.0 |
) |
|
Estimated Adjusted EBITDA |
$ |
3,600.0 |
|
|
(1) 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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