Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported fourth quarter and full year 2023 results.
Fourth quarter 2023 net income attributable to
Targa Resources Corp. was $299.6 million compared to $318.0 million
for the fourth quarter of 2022. For full year 2023, net income
attributable to Targa Resources Corp. was a record $1,345.9 million
compared to $1,195.5 million for 2022.
Highlights
- Record full year adjusted EBITDA(1)
for 2023 of $3,530.0 million, a 22% increase over 2022
- Record full year 2023 Permian, NGL
transportation, fractionation, and LPG export volumes
- Record full year 2023 common share
repurchases of $373.7 million
- Exiting 2023 with ~90% of Gathering
and Processing (“G&P”) volumes fee or fee-floor based
- Record quarterly adjusted EBITDA(1)
for the fourth quarter of $959.9 million, a 14% sequential
increase
- Record Permian, NGL transportation,
fractionation, and LPG export volumes during the fourth
quarter
- Completed its new 275 million cubic
feet per day (“MMcf/d”) Wildcat II plant in Permian Delaware
- Estimate 2024 adjusted EBITDA
between $3.7 billion and $3.9 billion, an 8% increase over
2023
- Estimate 2024 net growth capital
expenditures of $2.3 billion to $2.5 billion
- Continue to expect an annual common
dividend per share of $3.00 in 2024, a 50% increase to 2023
- Current estimate is ~$1.4 billion
of net growth capital expenditures in 2025, which would drive a
meaningful increase in adjusted free cash flow(1) in 2025
Targa’s record operational and financial results
in 2023 despite a significantly lower commodity price environment
demonstrates the resiliency of its diversified operations and
growing fee based midstream businesses.
The Company reported adjusted earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“adjusted EBITDA”) of $959.9 million for the fourth
quarter of 2023 compared to $840.4 million for the fourth quarter
of 2022. For the full year 2023, the Company reported adjusted
EBITDA of $3,530.0 million compared to $2,901.1 million for the
full year 2022.
The Company reported distributable cash flow and
adjusted free cash flow for the fourth quarter of 2023 of $709.7
million and $73.7 million, respectively. For the full year 2023,
the Company reported distributable cash flow and adjusted free cash
flow of $2,617.2 million and $392.7 million, respectively.
On January 18, 2024, the Company declared a
quarterly cash dividend of $0.50 per common share for the fourth
quarter of 2023, or $2.00 per common share on an annualized basis.
Total cash dividends of approximately $112 million will be paid on
February 15, 2024 on all outstanding shares of common stock to
holders of record as of the close of business on January 31, 2024.
The expected higher annual common dividend of $3.00 per share for
2024 should begin quarterly payments with the first quarter payment
in May of 2024.
Targa repurchased 475,040 shares of its common
stock during the fourth quarter of 2023 at a weighted average per
share price of $85.52 for a total net cost of $40.6 million. For
the year ended December 31, 2023, Targa repurchased 4,870,559
shares of its common stock at a weighted average price of $76.72
for a total net cost of $373.7 million. There was $770.1 million
remaining under the Company’s $1.0 billion common share repurchase
program as of December 31, 2023.
Fourth Quarter 2023 - Sequential Quarter
over Quarter Commentary
Targa reported fourth quarter adjusted EBITDA of
$959.9 million, representing a 14 percent increase compared to the
third quarter of 2023. The sequential increase in adjusted EBITDA
was attributable to higher volumes across Targa’s G&P and
Logistics and Transportation (“L&T”) systems. In the G&P
segment, higher sequential adjusted operating margin was
attributable to record Permian natural gas inlet volumes and higher
fees. In the L&T segment, record NGL pipeline transportation,
fractionation, and LPG export volumes and higher marketing margin
drove the sequential increase in segment adjusted operating margin.
Increasing NGL pipeline transportation and fractionation volumes
were attributable to higher supply volumes from Targa’s Permian
G&P systems and third parties. LPG export volumes benefited
from Targa’s system expansion completed in late third quarter of
2023 and improved market conditions, while marketing margin was
higher due to increased seasonal optimization opportunities.
Capitalization and
Liquidity
The Company’s total consolidated debt as of
December 31, 2023 was $12,953.9 million, net of $90.8 million of
debt issuance costs and $29.5 million of unamortized discount, with
$11,534.4 million of outstanding senior notes, $500.0 million
outstanding under the Company’s $1.5 billion term loan facility,
$175.0 million outstanding under the Commercial Paper Program,
$575.0 million outstanding under the Securitization Facility, and
$289.8 million of finance lease liabilities.
Total consolidated liquidity as of December 31,
2023 was approximately $2.7 billion, including $2.6 billion
available under the TRGP Revolver, $141.7 million of cash and $25.0
million available under the Securitization Facility.
Financing Update
In November 2023, Targa completed an
underwritten public offering of (i) $1.0 billion in aggregate
principal amount of its 6.150% Senior Notes due 2029 (the “2023
6.150% Notes”) and (ii) $1.0 billion in aggregate principal amount
of its 6.500% Senior Notes due 2034 (the “November 2023 6.500%
Notes”), resulting in net proceeds of approximately $2.0 billion.
Targa used a portion of the net proceeds to repay $1.0 billion in
borrowings under the Term Loan Facility and the remaining net
proceeds for general corporate purposes, including to repay
borrowings under the Commercial Paper Program.
Growth Projects Update
Late in the fourth quarter, Targa commenced
operations at its new 275 MMcf/d Wildcat II plant in Permian
Delaware ahead of schedule and on-budget. Construction continues on
its 275 MMcf/d Greenwood II plant in Permian Midland, and its 230
MMcf/d Roadrunner II and 275 MMcf/d Bull Moose plants in Permian
Delaware. In its L&T segment, construction continues on Targa’s
120 thousand barrels per day (“MBbl/d”) Train 9 fractionator and
its 120 MBbl/d Train 10 fractionator in Mont Belvieu, Texas, its
Daytona NGL Pipeline and Targa continues to make progress on the
reactivation of Gulf Coast Fractionators (“GCF”). Targa remains
on-track to complete these expansions as previously disclosed.
In response to increasing production and to meet
the infrastructure needs of its customers, Targa has commenced
spending on long-lead time items for its next gas plants in the
Permian Basin and its next fractionator in Mont Belvieu (“Train
11”).
2024 Outlook and Capital Return
Expectations
Targa’s 2024 operational and financial
expectations assume Waha natural gas prices average $1.80 per
million British Thermal Units (“MMbtu”), natural gas liquids
(“NGL”) composite barrel prices average $0.65 per gallon, and crude
oil prices average $75 per barrel.
For 2024, Targa estimates full year adjusted
EBITDA to be between $3.7 billion and $3.9 billion, with the
midpoint of the range representing an 8 percent increase over full
year 2023 adjusted EBITDA. Targa expects to continue to benefit
from meaningful growth across its Permian G&P footprint, which
is expected to drive record Permian, NGL pipeline transportation,
fractionation, and LPG export volumes in 2024 relative to the
records set in 2023. Organic growth capital projects coming online
in 2024, including two Permian G&P plants, two fractionators
and the Daytona NGL Pipeline, are expected to be highly utilized at
start-up, supporting increasing adjusted EBITDA in 2024 and beyond.
Additionally, Targa continued to make significant progress in
adding fees and fee floors to its G&P contracts and exits 2023
with approximately 90 percent of G&P volumes fee or fee-floor
based, providing cash flow stability and protection against further
downward movements in commodity prices.
Targa’s estimate for 2024 net growth capital
expenditures is between $2.3 billion to $2.5 billion and includes
spending on long-lead time items for its next gas plants in the
Permian Basin and Train 11. Net maintenance capital expenditures
for 2024 are estimated to be approximately $225 million.
For the first quarter of 2024, Targa intends to
recommend to its Board of Directors an increase to its common
dividend to $0.75 per common share or $3.00 per common share
annualized. The recommended common dividend per share increase, if
approved, would be effective for the first quarter of 2024 and
payable in May 2024. Beyond 2024, Targa expects to be in position
to continue to meaningfully increase the capital returned to
shareholders through increasing common dividends per share and
opportunistic repurchases of its common stock.
Positioning in 2025
For 2025, Targa estimates a meaningful step down
in net growth capital expenditures versus 2023 and 2024 as the
Company’s large downstream fractionation and NGL pipeline
transportation expansions will be complete by the first quarter of
2025.
Assuming continued production growth in the
Permian Basin consistent with consensus expectations and other key
assumptions, Targa’s current estimate is approximately $1.4 billion
of net growth capital expenditures in 2025. Given the key major
projects in progress that will be placed in service in 2024 and
early 2025, Targa expects a significant increase in adjusted EBITDA
in 2025 relative to 2024. The combination of decreasing growth
capital spending and increasing adjusted EBITDA is expected to
result in the generation of meaningful adjusted free cash flow and
a consolidated leverage ratio comfortably within Targa’s long-term
leverage ratio target range of 3 to 4 times. This would mean Targa
is well positioned to continue to provide its shareholders with a
meaningful increase in capital returned to shareholders through
increasing common dividends per share and continued common share
repurchases.
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 15, 2024 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/koukwuoq. A webcast replay will
be available at the link above approximately two hours after the
conclusion of the event.
(1) Adjusted EBITDA, distributable cash
flow and adjusted free cash flow are non-GAAP financial measures
and are discussed under “Non-GAAP Financial Measures.”
Targa Resources Corp. – Consolidated
Financial Results of Operations
|
Three Months Ended December 31, |
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
3,647.9 |
|
|
$ |
4,075.3 |
|
|
$ |
(427.4 |
) |
|
|
(10 |
%) |
|
$ |
13,962.1 |
|
|
$ |
19,066.0 |
|
|
$ |
(5,103.9 |
) |
|
|
(27 |
%) |
Fees from midstream services |
|
591.6 |
|
|
|
479.4 |
|
|
|
112.2 |
|
|
|
23 |
% |
|
|
2,098.2 |
|
|
|
1,863.8 |
|
|
|
234.4 |
|
|
|
13 |
% |
Total revenues |
|
4,239.5 |
|
|
|
4,554.7 |
|
|
|
(315.2 |
) |
|
|
(7 |
%) |
|
|
16,060.3 |
|
|
|
20,929.8 |
|
|
|
(4,869.5 |
) |
|
|
(23 |
%) |
Product purchases and
fuel |
|
2,898.5 |
|
|
|
3,324.2 |
|
|
|
(425.7 |
) |
|
|
(13 |
%) |
|
|
10,676.4 |
|
|
|
16,882.1 |
|
|
|
(6,205.7 |
) |
|
|
(37 |
%) |
Operating expenses |
|
269.5 |
|
|
|
252.2 |
|
|
|
17.3 |
|
|
|
7 |
% |
|
|
1,077.9 |
|
|
|
912.8 |
|
|
|
165.1 |
|
|
|
18 |
% |
Depreciation and amortization
expense |
|
341.4 |
|
|
|
329.8 |
|
|
|
11.6 |
|
|
|
4 |
% |
|
|
1,329.6 |
|
|
|
1,096.0 |
|
|
|
233.6 |
|
|
|
21 |
% |
General and administrative
expense |
|
95.3 |
|
|
|
92.5 |
|
|
|
2.8 |
|
|
|
3 |
% |
|
|
348.7 |
|
|
|
309.7 |
|
|
|
39.0 |
|
|
|
13 |
% |
Other operating (income)
expense |
|
(0.5 |
) |
|
|
4.7 |
|
|
|
(5.2 |
) |
|
|
(111 |
%) |
|
|
1.5 |
|
|
|
0.2 |
|
|
|
1.3 |
|
NM |
|
Income (loss) from
operations |
|
635.3 |
|
|
|
551.3 |
|
|
|
84.0 |
|
|
|
15 |
% |
|
|
2,626.2 |
|
|
|
1,729.0 |
|
|
|
897.2 |
|
|
|
52 |
% |
Interest expense, net |
|
(178.0 |
) |
|
|
(145.6 |
) |
|
|
(32.4 |
) |
|
|
22 |
% |
|
|
(687.8 |
) |
|
|
(446.1 |
) |
|
|
(241.7 |
) |
|
|
54 |
% |
Equity earnings (loss) |
|
2.8 |
|
|
|
0.3 |
|
|
|
2.5 |
|
|
NM |
|
|
|
9.0 |
|
|
|
9.1 |
|
|
|
(0.1 |
) |
|
|
(1 |
%) |
Gain (loss) from financing
activities |
|
(2.1 |
) |
|
|
— |
|
|
|
(2.1 |
) |
|
|
(100 |
%) |
|
|
(2.1 |
) |
|
|
(49.6 |
) |
|
|
47.5 |
|
|
|
96 |
% |
Gain (loss) from sale of
equity method investment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
435.9 |
|
|
|
(435.9 |
) |
|
|
(100 |
%) |
Other, net |
|
2.1 |
|
|
|
(0.3 |
) |
|
|
2.4 |
|
|
NM |
|
|
|
(2.8 |
) |
|
|
(15.1 |
) |
|
|
12.3 |
|
|
|
81 |
% |
Income tax (expense)
benefit |
|
(102.5 |
) |
|
|
(9.8 |
) |
|
|
(92.7 |
) |
|
NM |
|
|
|
(363.2 |
) |
|
|
(131.8 |
) |
|
|
(231.4 |
) |
|
|
176 |
% |
Net income (loss) |
|
357.6 |
|
|
|
395.9 |
|
|
|
(38.3 |
) |
|
|
(10 |
%) |
|
|
1,579.3 |
|
|
|
1,531.4 |
|
|
|
47.9 |
|
|
|
3 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
58.0 |
|
|
|
77.9 |
|
|
|
(19.9 |
) |
|
|
(26 |
%) |
|
|
233.4 |
|
|
|
335.9 |
|
|
|
(102.5 |
) |
|
|
(31 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
299.6 |
|
|
|
318.0 |
|
|
|
(18.4 |
) |
|
|
(6 |
%) |
|
|
1,345.9 |
|
|
|
1,195.5 |
|
|
|
150.4 |
|
|
|
13 |
% |
Premium on repurchase of
noncontrolling interests, net of tax |
|
19.4 |
|
|
|
0.1 |
|
|
|
19.3 |
|
|
NM |
|
|
|
510.1 |
|
|
|
53.2 |
|
|
|
456.9 |
|
NM |
|
Dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
30.0 |
|
|
|
(30.0 |
) |
|
|
(100 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
215.5 |
|
|
|
(215.5 |
) |
|
|
(100 |
%) |
Net income (loss) attributable
to common shareholders |
$ |
280.2 |
|
|
$ |
317.9 |
|
|
$ |
(37.7 |
) |
|
|
(12 |
%) |
|
$ |
835.8 |
|
|
$ |
896.8 |
|
|
$ |
(61.0 |
) |
|
|
(7 |
%) |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
959.9 |
|
|
$ |
840.4 |
|
|
$ |
119.5 |
|
|
|
14 |
% |
|
$ |
3,530.0 |
|
|
$ |
2,901.1 |
|
|
$ |
628.9 |
|
|
|
22 |
% |
Distributable cash flow
(1) |
|
709.7 |
|
|
|
655.5 |
|
|
|
54.2 |
|
|
|
8 |
% |
|
|
2,617.2 |
|
|
|
2,278.7 |
|
|
|
338.5 |
|
|
|
15 |
% |
Adjusted free cash flow
(1) |
|
73.7 |
|
|
|
103.1 |
|
|
|
(29.4 |
) |
|
|
(29 |
%) |
|
|
392.7 |
|
|
|
1,101.5 |
|
|
|
(708.8 |
) |
|
|
(64 |
%) |
(1) Adjusted EBITDA, distributable cash
flow and adjusted free cash flow are non-GAAP financial measures
and are discussed under “Non-GAAP Financial Measures.”NM Due
to a low denominator, the noted percentage change is
disproportionately high and as a result, considered not
meaningful.
Three Months Ended December 31, 2023 Compared to Three Months
Ended December 31, 2022
The decrease in commodity sales reflects lower
natural gas and NGL prices ($1,241.9 million), partially offset by
higher NGL and natural gas volumes ($792.8 million) and the
favorable impact of hedges ($19.6 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees, higher
export volumes and higher terminaling and storage fees, partially
offset by lower transportation and fractionation fees.
The decrease in product purchases and fuel
reflects lower natural gas and NGL prices, partially offset by
higher NGL and natural gas volumes.
The increase in operating expenses is primarily
due to higher labor and rental costs due to increased activity and
system expansions, the acquisition of certain assets in the
Delaware Basin and inflation.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the impact of system expansions on the
Company’s asset base, partially offset by the shortening of the
depreciable lives of certain assets that were idled in 2022.
The increase in interest expense, net is due to
higher net borrowings primarily for the Grand Prix Transaction and
higher interest rates, partially offset by higher capitalized
interest resulting from higher growth capital investments.
The increase in income tax expense is primarily
due to a smaller release of the valuation allowance in 2023
compared to 2022, the impact of rate changes and a lower benefit
related to income allocated to noncontrolling interest that is not
taxable to the Company.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the Grand Prix
Transaction and lower earnings allocated to the Company’s joint
venture partner in WestTX, partially offset by higher earnings
allocated to the Company's joint venture partner in Venice Energy
Services Company, L.L.C.
Year Ended December 31, 2023 Compared to Year
Ended December 31, 2022
The decrease in commodity sales reflects lower
NGL, natural gas and condensate prices ($9,255.7 million),
partially offset by higher NGL, natural gas and condensate volumes
($2,951.9 million) and the favorable impact of hedges ($1,195.8
million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees including
the impact of the acquisition of certain assets in the Delaware
Basin and South Texas, and higher export volumes, partially offset
by lower transportation and fractionation fees.
The decrease in product purchases and fuel
reflects lower NGL, natural gas and condensate prices, partially
offset by higher NGL, natural gas and condensate volumes.
The increase in operating expenses is primarily
due to higher labor, maintenance and rental costs due to increased
activity and system expansions, the acquisition of certain assets
in the Delaware Basin and South Texas, and inflation.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to the acquisition of certain assets in
the Delaware Basin and the impact of system expansions on the
Company’s asset base, partially offset by the shortening of
depreciable lives of certain assets that were idled in 2022.
The increase in general and administrative
expense is primarily due to higher compensation and benefits,
insurance costs, computer systems and professional fees.
The increase in interest expense, net is due to
higher net borrowings primarily for the acquisition of certain
assets in the Delaware Basin and the Grand Prix Transaction, and
higher interest rates, partially offset by higher capitalized
interest resulting from higher growth capital investments.
During 2022, the Company terminated the previous
TRGP senior secured revolving credit facility and the Partnership’s
senior secured revolving credit facility. In addition, the
Partnership redeemed its 5.375% Senior Notes due 2027 and its
5.875% Senior Notes due 2026. These transactions resulted in a net
loss from financing activities.
During 2022, the Company completed the sale of
Targa GCX Pipeline LLC, which held a 25% equity interest in Gulf
Coast Express Pipeline to a third party for $857 million resulting
in a gain from sale of an equity method investment.
The increase in income tax expense is primarily
due to an increase in pre-tax book income and a smaller release of
the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable
to noncontrolling interests is primarily due to the Grand Prix
Transaction and lower earnings allocated to the Company’s joint
venture partner in WestTX.
The premium on repurchase of noncontrolling
interests, net of tax is primarily due to the Grand Prix
Transaction in 2023 and the purchase of all of Stonepeak
Infrastructure Partners’ interests in the Company’s development
company joint ventures in 2022.
The decrease in dividends on Series A Preferred
Stock (“Series A Preferred”) is due to the full redemption of all
of the Company’s issued and outstanding shares of Series A
Preferred in May 2022.
Review of Segment
Performance
The following discussion of segment performance
includes inter-segment activities. The Company views segment
operating margin and adjusted operating margin as important
performance measures of the core profitability of its operations.
These measures are key components of internal financial reporting
and are reviewed for consistency and trend analysis. For a
discussion of adjusted operating margin, see “Non-GAAP Financial
Measures ― Adjusted Operating Margin.” Segment operating financial
results and operating statistics include the effects of
intersegment transactions. These intersegment transactions have
been eliminated from the consolidated presentation.
The Company operates in two primary segments:
(i) Gathering and Processing; and (ii) Logistics and
Transportation.
Gathering and Processing
Segment
The Gathering and Processing segment includes
assets used in the gathering and/or purchase and sale of natural
gas produced from oil and gas wells, removing impurities and
processing this raw natural gas into merchantable natural gas by
extracting NGLs; and assets used for the gathering and terminaling
and/or purchase and sale of crude oil. The Gathering and Processing
segment’s assets are located in the Permian Basin of West Texas and
Southeast New Mexico (including the Midland, Central and Delaware
Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in
North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma
(including the SCOOP and STACK) and South Central Kansas; the
Williston Basin in North Dakota (including the Bakken and Three
Forks plays); and the onshore and near offshore regions of the
Louisiana Gulf Coast and the Gulf of Mexico.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
|
Three Months Ended December 31, |
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
536.3 |
|
|
$ |
544.0 |
|
|
$ |
(7.7 |
) |
|
|
(1 |
%) |
|
$ |
2,082.2 |
|
|
$ |
1,981.0 |
|
|
$ |
101.2 |
|
|
|
5 |
% |
Operating expenses |
|
185.7 |
|
|
|
177.3 |
|
|
|
8.4 |
|
|
|
5 |
% |
|
|
746.6 |
|
|
|
611.8 |
|
|
|
134.8 |
|
|
|
22 |
% |
Adjusted operating margin |
$ |
722.0 |
|
|
$ |
721.3 |
|
|
$ |
0.7 |
|
|
|
— |
|
|
$ |
2,828.8 |
|
|
$ |
2,592.8 |
|
|
$ |
236.0 |
|
|
|
9 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
2,716.5 |
|
|
|
2,376.0 |
|
|
|
340.5 |
|
|
|
14 |
% |
|
|
2,535.2 |
|
|
|
2,223.6 |
|
|
|
311.6 |
|
|
|
14 |
% |
Permian Delaware (5) |
|
2,564.3 |
|
|
|
2,371.3 |
|
|
|
193.0 |
|
|
|
8 |
% |
|
|
2,526.5 |
|
|
|
1,536.1 |
|
|
|
990.4 |
|
|
|
64 |
% |
Total Permian |
|
5,280.8 |
|
|
|
4,747.3 |
|
|
|
533.5 |
|
|
|
11 |
% |
|
|
5,061.7 |
|
|
|
3,759.7 |
|
|
|
1,302.0 |
|
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
347.9 |
|
|
|
334.7 |
|
|
|
13.2 |
|
|
|
4 |
% |
|
|
367.4 |
|
|
|
276.5 |
|
|
|
90.9 |
|
|
|
33 |
% |
North Texas |
|
207.7 |
|
|
|
219.4 |
|
|
|
(11.7 |
) |
|
|
(5 |
%) |
|
|
205.9 |
|
|
|
187.0 |
|
|
|
18.9 |
|
|
|
10 |
% |
SouthOK (6) |
|
366.5 |
|
|
|
359.7 |
|
|
|
6.8 |
|
|
|
2 |
% |
|
|
385.0 |
|
|
|
406.8 |
|
|
|
(21.8 |
) |
|
|
(5 |
%) |
WestOK |
|
207.1 |
|
|
|
207.3 |
|
|
|
(0.2 |
) |
|
|
— |
|
|
|
207.1 |
|
|
|
208.7 |
|
|
|
(1.6 |
) |
|
|
(1 |
%) |
Total Central |
|
1,129.2 |
|
|
|
1,121.1 |
|
|
|
8.1 |
|
|
|
1 |
% |
|
|
1,165.4 |
|
|
|
1,079.0 |
|
|
|
86.4 |
|
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) (7) |
|
131.2 |
|
|
|
140.2 |
|
|
|
(9.0 |
) |
|
|
(6 |
%) |
|
|
130.0 |
|
|
|
134.9 |
|
|
|
(4.9 |
) |
|
|
(4 |
%) |
Total Field |
|
6,541.2 |
|
|
|
6,008.6 |
|
|
|
532.6 |
|
|
|
9 |
% |
|
|
6,357.1 |
|
|
|
4,973.6 |
|
|
|
1,383.5 |
|
|
|
28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
567.0 |
|
|
|
457.3 |
|
|
|
109.7 |
|
|
|
24 |
% |
|
|
541.1 |
|
|
|
537.6 |
|
|
|
3.5 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
7,108.2 |
|
|
|
6,465.9 |
|
|
|
642.3 |
|
|
|
10 |
% |
|
|
6,898.2 |
|
|
|
5,511.2 |
|
|
|
1,387.0 |
|
|
|
25 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
398.3 |
|
|
|
342.0 |
|
|
|
56.3 |
|
|
|
16 |
% |
|
|
367.7 |
|
|
|
321.7 |
|
|
|
46.0 |
|
|
|
14 |
% |
Permian Delaware (5) |
|
310.6 |
|
|
|
276.1 |
|
|
|
34.5 |
|
|
|
12 |
% |
|
|
321.6 |
|
|
|
188.6 |
|
|
|
133.0 |
|
|
|
71 |
% |
Total Permian |
|
708.9 |
|
|
|
618.1 |
|
|
|
90.8 |
|
|
|
15 |
% |
|
|
689.3 |
|
|
|
510.3 |
|
|
|
179.0 |
|
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (6) |
|
37.3 |
|
|
|
34.2 |
|
|
|
3.1 |
|
|
|
9 |
% |
|
|
40.9 |
|
|
|
31.2 |
|
|
|
9.7 |
|
|
|
31 |
% |
North Texas |
|
24.5 |
|
|
|
25.2 |
|
|
|
(0.7 |
) |
|
|
(3 |
%) |
|
|
24.0 |
|
|
|
21.2 |
|
|
|
2.8 |
|
|
|
13 |
% |
SouthOK (6) |
|
40.0 |
|
|
|
36.3 |
|
|
|
3.7 |
|
|
|
10 |
% |
|
|
43.1 |
|
|
|
47.6 |
|
|
|
(4.5 |
) |
|
|
(9 |
%) |
WestOK |
|
12.1 |
|
|
|
12.1 |
|
|
|
— |
|
|
|
— |
|
|
|
12.5 |
|
|
|
14.6 |
|
|
|
(2.1 |
) |
|
|
(14 |
%) |
Total Central |
|
113.9 |
|
|
|
107.8 |
|
|
|
6.1 |
|
|
|
6 |
% |
|
|
120.5 |
|
|
|
114.6 |
|
|
|
5.9 |
|
|
|
5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
15.7 |
|
|
|
17.0 |
|
|
|
(1.3 |
) |
|
|
(8 |
%) |
|
|
15.5 |
|
|
|
16.1 |
|
|
|
(0.6 |
) |
|
|
(4 |
%) |
Total Field |
|
838.5 |
|
|
|
742.9 |
|
|
|
95.6 |
|
|
|
13 |
% |
|
|
825.3 |
|
|
|
641.0 |
|
|
|
184.3 |
|
|
|
29 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
43.2 |
|
|
|
22.9 |
|
|
|
20.3 |
|
|
|
89 |
% |
|
|
39.2 |
|
|
|
32.0 |
|
|
|
7.2 |
|
|
|
23 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
881.7 |
|
|
|
765.8 |
|
|
|
115.9 |
|
|
|
15 |
% |
|
|
864.5 |
|
|
|
673.0 |
|
|
|
191.5 |
|
|
|
28 |
% |
Crude oil, Badlands,
MBbl/d |
|
105.2 |
|
|
|
113.7 |
|
|
|
(8.5 |
) |
|
|
(7 |
%) |
|
|
105.5 |
|
|
|
117.6 |
|
|
|
(12.1 |
) |
|
|
(10 |
%) |
Crude oil, Permian,
MBbl/d |
|
27.5 |
|
|
|
28.4 |
|
|
|
(0.9 |
) |
|
|
(3 |
%) |
|
|
27.4 |
|
|
|
29.5 |
|
|
|
(2.1 |
) |
|
|
(7 |
%) |
Natural gas sales, BBtu/d
(3) |
|
2,737.3 |
|
|
|
2,665.3 |
|
|
|
72.0 |
|
|
|
3 |
% |
|
|
2,685.8 |
|
|
|
2,383.4 |
|
|
|
302.4 |
|
|
|
13 |
% |
NGL sales, MBbl/d (3) |
|
520.6 |
|
|
|
457.6 |
|
|
|
63.0 |
|
|
|
14 |
% |
|
|
495.8 |
|
|
|
439.8 |
|
|
|
56.0 |
|
|
|
13 |
% |
Condensate sales, MBbl/d |
|
17.8 |
|
|
|
16.3 |
|
|
|
1.5 |
|
|
|
9 |
% |
|
|
18.5 |
|
|
|
15.5 |
|
|
|
3.0 |
|
|
|
19 |
% |
Average realized
prices (8): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
1.83 |
|
|
|
3.94 |
|
|
|
(2.11 |
) |
|
|
(54 |
%) |
|
|
1.94 |
|
|
|
5.21 |
|
|
|
(3.27 |
) |
|
|
(63 |
%) |
NGL, $/gal |
|
0.43 |
|
|
|
0.55 |
|
|
|
(0.12 |
) |
|
|
(22 |
%) |
|
|
0.46 |
|
|
|
0.75 |
|
|
|
(0.29 |
) |
|
|
(39 |
%) |
Condensate, $/Bbl |
|
74.79 |
|
|
|
77.21 |
|
|
|
(2.42 |
) |
|
|
(3 |
%) |
|
|
74.35 |
|
|
|
88.26 |
|
|
|
(13.91 |
) |
|
|
(16 |
%) |
(1) Segment operating statistics include
the effect of intersegment amounts, which have been eliminated from
the consolidated presentation. For all volume statistics presented,
the numerator is the total volume sold during the period and the
denominator is the number of calendar days during the
period.(2) Plant natural gas inlet represents the Company’s
undivided interest in the volume of natural gas passing through the
meter located at the inlet of a natural gas processing plant, other
than Badlands.(3) Plant natural gas inlet volumes and gross
NGL production volumes include producer take-in-kind volumes, while
natural gas sales and NGL sales exclude producer take-in-kind
volumes.(4) Permian Midland includes operations in WestTX, of
which the Company owns a 72.8% undivided interest, and other plants
that are owned 100% by the Company. Operating results for the
WestTX undivided interest assets are presented on a pro-rata net
basis in the Company’s reported financials.(5) Includes
operations from the acquisition of certain assets in the Delaware
Basin for the period effective August 1, 2022.(6) Operations
include facilities that are not wholly owned by the Company.
SouthTX operating statistics include the impact of the acquisition
of certain assets in South Texas for the period effective April 21,
2022.(7) Badlands natural gas inlet represents the total
wellhead volume and includes the Targa volumes processed at the
Little Missouri 4 plant.(8) Average realized prices, net of
fees, include the effect of realized commodity hedge gain/loss
attributable to the Company’s equity volumes. The price is
calculated using total commodity sales plus the hedge gain/loss as
the numerator and total sales volume as the denominator, net of
fees.
The following table presents the realized
commodity hedge gain (loss) attributable to the Company’s equity
volumes that are included in the adjusted operating margin of the
Gathering and Processing segment:
|
Three Months Ended December 31, 2023 |
|
|
Three Months Ended December 31, 2022 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
13.2 |
|
|
$ |
1.15 |
|
|
$ |
15.2 |
|
|
|
20.2 |
|
|
$ |
(0.02 |
) |
|
$ |
(0.4 |
) |
NGL (MMgal) |
|
165.3 |
|
|
|
0.09 |
|
|
|
15.5 |
|
|
|
187.9 |
|
|
|
(0.04 |
) |
|
|
(7.8 |
) |
Crude oil (MBbl) |
|
0.6 |
|
|
|
(6.17 |
) |
|
|
(3.7 |
) |
|
|
0.6 |
|
|
|
(14.22 |
) |
|
|
(8.5 |
) |
|
|
|
|
|
|
|
$ |
27.0 |
|
|
|
|
|
|
|
|
$ |
(16.7 |
) |
|
Year Ended December 31, 2023 |
|
|
Year Ended December 31, 2022 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
63.2 |
|
|
$ |
1.22 |
|
|
$ |
77.4 |
|
|
|
74.8 |
|
|
$ |
(2.13 |
) |
|
$ |
(159.2 |
) |
NGL (MMgal) |
|
680.3 |
|
|
|
0.07 |
|
|
|
49.9 |
|
|
|
717.6 |
|
|
|
(0.30 |
) |
|
|
(213.0 |
) |
Crude oil (MBbl) |
|
2.4 |
|
|
|
(6.92 |
) |
|
|
(16.6 |
) |
|
|
2.2 |
|
|
|
(31.73 |
) |
|
|
(69.8 |
) |
|
|
|
|
|
|
|
$ |
110.7 |
|
|
|
|
|
|
|
|
$ |
(442.0 |
) |
(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, 2023 Compared to
Three Months Ended December 31, 2022
The adjusted operating margin was relatively
flat and higher natural gas inlet volumes and higher fees
predominantly in the Permian were offset by lower commodity prices.
The increase in natural gas inlet volumes in the Permian was
attributable to the addition of the Legacy II plant during the
first quarter of 2023, the Midway plant during the second quarter
of 2023, and the Greenwood plant during the fourth quarter of 2023,
and continued strong producer activity. The natural gas inlet
volumes in the Coastal region increased primarily due to plant
outages in the fourth quarter of 2022.
The increase in operating expenses was primarily
due to higher volumes in the Permian, the addition of the Legacy
II, Midway, Greenwood and Wildcat II plants, increased professional
services, and inflation impacts.
Year Ended December 31, 2023 Compared to Year Ended December 31,
2022
The increase in adjusted operating margin was
due to higher natural gas inlet volumes and higher fees resulting
in increased margin predominantly in the Permian, partially offset
by lower commodity prices. The increase in natural gas inlet
volumes in the Permian was attributable to the acquisition of
certain assets in the Delaware Basin during the third quarter of
2022, the addition of the Legacy I and Red Hills VI plants during
the third quarter of 2022, the Legacy II plant during the first
quarter of 2023, the Greenwood plant during the fourth quarter of
2023, and continued strong producer activity. Natural gas inlet
volumes in the Central region increased due to the acquisition of
certain assets in South Texas during the second quarter of 2022 and
increased producer activity.
The increase in operating expenses was
predominantly due to the acquisition of certain assets in the
Delaware Basin and South Texas. Additionally, higher volumes in the
Permian, the addition of the Legacy I, Red Hills VI, Legacy II,
Midway, Greenwood and Wildcat II plants, and inflation impacts
resulted in increased costs.
Logistics and Transportation
Segment
The Logistics and Transportation segment
includes the activities and assets necessary to convert mixed NGLs
into NGL products and also includes other assets and value-added
services such as transporting, storing, fractionating, terminaling,
and marketing of NGLs and NGL products, including services to LPG
exporters and certain natural gas supply and marketing activities
in support of the Company’s other businesses. The Logistics and
Transportation segment also includes Grand Prix NGL Pipeline, which
connects the Company’s gathering and processing positions in the
Permian Basin, Southern Oklahoma and North Texas with the Company’s
Downstream facilities in Mont Belvieu, Texas. The associated assets
are generally connected to and supplied in part by the Company’s
Gathering and Processing segment and, except for the pipelines and
smaller terminals, are located predominantly in Mont Belvieu and
Galena Park, Texas, and in Lake Charles, Louisiana.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
|
Three Months Ended December 31, |
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
(In millions, except operating statistics) |
Operating margin |
$ |
554.2 |
|
|
$ |
441.6 |
|
|
$ |
112.6 |
|
|
|
25 |
% |
|
$ |
1,948.7 |
|
|
$ |
1,456.3 |
|
|
$ |
492.4 |
|
|
|
34 |
% |
Operating expenses |
|
84.4 |
|
|
|
74.4 |
|
|
|
10.0 |
|
|
|
13 |
% |
|
|
332.0 |
|
|
|
300.2 |
|
|
|
31.8 |
|
|
|
11 |
% |
Adjusted operating margin |
$ |
638.6 |
|
|
$ |
516.0 |
|
|
$ |
122.6 |
|
|
|
24 |
% |
|
$ |
2,280.7 |
|
|
$ |
1,756.5 |
|
|
$ |
524.2 |
|
|
|
30 |
% |
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
722.0 |
|
|
|
502.3 |
|
|
|
219.7 |
|
|
|
44 |
% |
|
|
635.5 |
|
|
|
488.6 |
|
|
|
146.9 |
|
|
|
30 |
% |
Fractionation volumes |
|
844.8 |
|
|
|
744.4 |
|
|
|
100.4 |
|
|
|
13 |
% |
|
|
798.1 |
|
|
|
731.7 |
|
|
|
66.4 |
|
|
|
9 |
% |
Export volumes (3) |
|
434.5 |
|
|
|
299.4 |
|
|
|
135.1 |
|
|
|
45 |
% |
|
|
365.2 |
|
|
|
314.5 |
|
|
|
50.7 |
|
|
|
16 |
% |
NGL sales |
|
1,125.8 |
|
|
|
861.0 |
|
|
|
264.8 |
|
|
|
31 |
% |
|
|
1,019.8 |
|
|
|
866.3 |
|
|
|
153.5 |
|
|
|
18 |
% |
(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, 2023 Compared to
Three Months Ended December 31, 2022
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin and
higher LPG export 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. LPG export margin
increased due to the completion of the expansion during the third
quarter of 2023 resulting in higher volumes and fees. Greater
seasonal optimization opportunities drove higher marketing margin
in the fourth quarter of 2022.
The increase in operating expenses was due to
higher system volumes, higher repairs and maintenance and higher
compensation and benefits.
Year Ended December 31, 2023 Compared to Year Ended December 31,
2022
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation margin,
higher marketing margin, and higher LPG export margin. Pipeline
transportation and fractionation volumes benefited from higher
supply volumes primarily from the Company’s Permian Gathering and
Processing systems and higher fees. Marketing margin increased due
to greater optimization opportunities. LPG Export margin increased
due to the completion of the expansion during the third quarter of
2023 resulting in higher volumes and fees.
The increase in operating expenses was due to
higher system volumes, higher compensation and benefits, higher
repairs and maintenance and higher taxes.
Other
|
Three Months Ended December 31, |
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
2023 |
|
|
2022 |
|
|
2023 vs. 2022 |
|
|
(In millions) |
|
Operating margin |
$ |
(18.8 |
) |
|
$ |
(7.5 |
) |
|
$ |
(11.3 |
) |
|
$ |
275.5 |
|
|
$ |
(302.4 |
) |
|
$ |
577.9 |
|
Adjusted operating margin |
$ |
(18.8 |
) |
|
$ |
(7.5 |
) |
|
$ |
(11.3 |
) |
|
$ |
275.5 |
|
|
$ |
(302.4 |
) |
|
$ |
577.9 |
|
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, |
|
|
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
|
(In millions) |
|
Reconciliation of Net
income (loss) attributable to Targa Resources Corp. to Adjusted
EBITDA, Distributable Cash Flow and Adjusted Free Cash
Flow |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Corp. |
$ |
299.6 |
|
|
$ |
318.0 |
|
|
$ |
1,345.9 |
|
|
$ |
1,195.5 |
|
Interest (income) expense, net |
|
178.0 |
|
|
|
145.6 |
|
|
|
687.8 |
|
|
|
446.1 |
|
Income tax expense (benefit) |
|
102.5 |
|
|
|
9.8 |
|
|
|
363.2 |
|
|
|
131.8 |
|
Depreciation and amortization expense |
|
341.4 |
|
|
|
329.8 |
|
|
|
1,329.6 |
|
|
|
1,096.0 |
|
(Gain) loss on sale or disposition of assets |
|
(1.3 |
) |
|
|
(1.5 |
) |
|
|
(5.3 |
) |
|
|
(9.6 |
) |
Write-down of assets |
|
0.8 |
|
|
|
6.2 |
|
|
|
6.9 |
|
|
|
9.8 |
|
(Gain) loss from financing activities (1) |
|
2.1 |
|
|
|
— |
|
|
|
2.1 |
|
|
|
49.6 |
|
(Gain) loss from sale of equity method investment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(435.9 |
) |
Transaction costs related to business acquisition (2) |
|
— |
|
|
|
3.6 |
|
|
|
— |
|
|
|
23.9 |
|
Equity (earnings) loss |
|
(2.8 |
) |
|
|
(0.3 |
) |
|
|
(9.0 |
) |
|
|
(9.1 |
) |
Distributions (contributions) from unconsolidated affiliates,
net |
|
4.5 |
|
|
|
5.5 |
|
|
|
18.6 |
|
|
|
27.2 |
|
Compensation on equity grants |
|
16.7 |
|
|
|
15.7 |
|
|
|
62.4 |
|
|
|
57.5 |
|
Risk management activities |
|
18.8 |
|
|
|
7.5 |
|
|
|
(275.4 |
) |
|
|
302.5 |
|
Noncontrolling interests adjustments (3) |
|
(0.4 |
) |
|
|
0.5 |
|
|
|
(3.7 |
) |
|
|
15.8 |
|
Litigation expense (4) |
|
— |
|
|
|
— |
|
|
|
6.9 |
|
|
|
— |
|
Adjusted
EBITDA |
$ |
959.9 |
|
|
$ |
840.4 |
|
|
$ |
3,530.0 |
|
|
$ |
2,901.1 |
|
Interest expense on debt obligations (5) |
|
(174.9 |
) |
|
|
(142.5 |
) |
|
|
(675.8 |
) |
|
|
(447.6 |
) |
Maintenance capital expenditures, net (6) |
|
(70.4 |
) |
|
|
(41.3 |
) |
|
|
(223.4 |
) |
|
|
(168.1 |
) |
Cash taxes |
|
(4.9 |
) |
|
|
(1.1 |
) |
|
|
(13.6 |
) |
|
|
(6.7 |
) |
Distributable Cash
Flow |
$ |
709.7 |
|
|
$ |
655.5 |
|
|
$ |
2,617.2 |
|
|
$ |
2,278.7 |
|
Growth capital expenditures, net (6) |
|
(636.0 |
) |
|
|
(552.4 |
) |
|
|
(2,224.5 |
) |
|
|
(1,177.2 |
) |
Adjusted Free Cash
Flow |
$ |
73.7 |
|
|
$ |
103.1 |
|
|
$ |
392.7 |
|
|
$ |
1,101.5 |
|
(1) Gains or losses on debt repurchases or
early debt extinguishments.(2) Includes financial advisory,
legal and other professional fees, and other one-time transaction
costs.(3) Noncontrolling interest portion of depreciation and
amortization expense.(4) Litigation expense includes charges
related to litigation resulting from the major winter storm in
February 2021 that the Company considers outside the ordinary
course of its business and/or not reflective of its ongoing core
operations. The Company may incur such charges from time to time,
and the Company believes it is useful to exclude such charges
because it does not consider them reflective of its ongoing core
operations and because of the generally singular nature of the
claims underlying such litigation.(5) Excludes amortization
of debt issuance costs.(6) Represents capital expenditures,
net of contributions from noncontrolling interests and includes net
contributions to investments in unconsolidated affiliates.
The following table presents a reconciliation of estimated net
income of the Company to estimated adjusted EBITDA for 2024:
|
2024E |
|
|
(In millions) |
|
Reconciliation of
Estimated Net Income Attributable to Targa Resources Corp.
to |
|
|
Estimated Adjusted
EBITDA |
|
|
Net income attributable to Targa Resources Corp. |
$ |
1,185.0 |
|
Interest expense, net |
|
730.0 |
|
Income tax expense |
|
475.0 |
|
Depreciation and amortization expense |
|
1,350.0 |
|
Equity earnings |
|
(15.0 |
) |
Distributions from unconsolidated affiliates |
|
20.0 |
|
Compensation on equity grants |
|
65.0 |
|
Risk management and other |
|
— |
|
Noncontrolling interests adjustments (1) |
|
(10.0 |
) |
Estimated Adjusted EBITDA |
$ |
3,800.0 |
|
(1) Noncontrolling interest portion of
depreciation and amortization expense.
Regulation FD Disclosures
The Company uses any of the following to comply
with its disclosure obligations under Regulation FD: press
releases, SEC filings, public conference calls, or our website. The
Company routinely posts important information on its website at
www.targaresources.com, including information that may be deemed to
be material. The Company encourages investors and others interested
in the company to monitor these distribution channels for material
disclosures.
Forward-Looking Statements
Certain statements in this release are
“forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other
than statements of historical facts, included in this release that
address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future,
are forward-looking statements, including statements regarding our
projected financial performance, capital spending and payment of
future dividends. These forward-looking statements rely on a number
of assumptions concerning future events and are subject to a number
of uncertainties, factors and risks, many of which are outside the
Company’s control, which could cause results to differ materially
from those expected by management of the Company. Such risks and
uncertainties include, but are not limited to, actions by the
Organization of the Petroleum Exporting Countries (“OPEC”) and
non-OPEC oil producing countries, weather, political, economic and
market conditions, including a decline in the price and market
demand for natural gas, natural gas liquids and crude oil, the
timing and success of our completion of capital projects and
business development efforts, the expected growth of volumes on our
systems, the impact of pandemics or any other public health crises,
commodity price volatility due to ongoing or new global conflicts,
the impact of disruptions in the bank and capital markets,
including those resulting from lack of access to liquidity for
banking and financial services firms, and other uncertainties.
These and other applicable uncertainties, factors and risks are
described more fully in the Company’s filings with the Securities
and Exchange Commission, including its most recent Annual Report on
Form 10-K, and any subsequently filed Quarterly Reports on Form
10-Q and Current Reports on Form 8-K. The Company does not
undertake an obligation to update or revise any forward-looking
statement, whether as a result of new information, future events or
otherwise.
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
Grafico Azioni Targa Resources (NYSE:TRGP)
Storico
Da Apr 2024 a Mag 2024
Grafico Azioni Targa Resources (NYSE:TRGP)
Storico
Da Mag 2023 a Mag 2024