Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the
“Company”) today reported fourth-quarter and full-year 2024
results, provided first-quarter and full-year 2025 guidance, and
released a new three-year outlook for 2025 through 2027.
Key Takeaways & Updates
- For the fourth quarter of 2024, total barrels of oil equivalent
(BOE), oil production and natural gas production beat the high-end
of guidance by 3% or more and capital expenditures (non-GAAP) came
in near the low-end of guidance. Relative to our full-year 2024
guidance, total BOE, oil production and natural gas production
exceeded the high-end of guidance and capital expenditures
(non-GAAP) came in near the low-end of guidance. Dividends and
share repurchases totaled $218 million, or 61% of Free Cash Flow
(non-GAAP), in the fourth quarter of 2024 and $1,086 million, or
89% of full-year 2024 Free Cash Flow (non-GAAP).
- 2025 capital expenditures are expected to be between $2.1 and
$2.4 billion, in line with the 2025 pro forma framework announced
with our acquisitions in November 2024. Relative to last November,
Permian drilling and completion capital expenditures are estimated
to be approximately $70 million lower, driven by improved services
costs and acquisition synergies. Marcellus drilling and completion
capital expenditures are estimated to be approximately $50 million
higher than expected in November as we restart activity in the
basin early in the second quarter. Anadarko capital expenditures
are expected to be relatively consistent. At the mid-point of
capital, and based on current commodity price outlook, the
Company’s 2025 reinvestment rate (non-GAAP) is estimated to be
slightly below 50%.
- Our 2025 production guidance is unchanged at the midpoint from
the 2025 pro forma framework announced last November. 2025 total
BOE production is expected to be up approximately 9% year-over-year
at the mid-point, with oil volumes up approximately 47%, and
natural gas volumes relatively flat to 2024 levels. Our 2025
guidance includes the impact of the recent acquisitions from the
closings in late January. Organic 2025 annual oil and BOE growth
for Coterra’s legacy assets, excluding the recently closed
acquisitions, is estimated to be greater than 5% for oil and 0 to
5% for BOE.
- Updated three-year outlook (2025 through 2027) includes annual
average oil growth of 5% or greater, annual average BOE growth of 0
to 5% and an average annual capital range of $2.1 to $2.4 billion,
which includes legacy organic Coterra growth in 2025 and pro forma
combined growth in 2026 and 2027. This outlook reflects an average
reinvestment rate below 50% at the recent strip, pairing strong
capital efficiency with consistent production growth.
- The Company is announcing a 5% dividend increase to $0.22 per
share for the fourth quarter of 2024. The new annualized dividend
of $0.88 per share equates to a 3.1% yield, based on the Company's
$28.14 closing share price as of February 21, 2025.
- In late January 2025, the Company completed the previously
announced Permian acquisitions for aggregate consideration of
approximately $3.2 billion of cash and 28.2 million shares of
Coterra common stock, subject to post-closing purchase price
adjustments. These acquisitions, combined with previously owned
leaseholds, create a new focus area in the Northern Delaware basin
consisting of approximately 83,000 acres.
Tom Jorden, Chairman, CEO and President of Coterra, noted, “I am
proud to report that Coterra continued its trend of excellent
operational execution throughout 2024. Capital expenditures came in
near the low end and production was above the high end of guidance,
delivering improved capital efficiency. The team continues to
engineer better solutions across our operating regions through
decreased cycle times, increased productivity and lower costs.
Additionally, I am pleased to report that we closed on our
accretive Delaware Basin acquisitions on schedule, as well as
finished bringing online our large 57 well Culberson row
development. We enter 2025 with strong momentum in the Permian
Basin and we exited the year at a three-year production high in the
Marcellus. We are pleased to announce that we expect to restart our
Marcellus development program in the coming months, which will
provide incremental natural gas volumes next winter. We remain
committed to value creation through operational excellence,
disciplined capital allocation driven by full-cycle returns, and
returning value to shareholders.”
Fourth-Quarter 2024 Highlights
- Net Income (GAAP) totaled $297 million, or $0.40 per share.
Adjusted Net Income (non-GAAP) was $358 million, or $0.49 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $626
million. Discretionary Cash Flow (non-GAAP) totaled $776
million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $425 million. Capital
expenditures for drilling, completion and other fixed asset
additions (non-GAAP) totaled $417 million, near the low end of our
guidance range of $410 to $500 million.
- Free Cash Flow (non-GAAP) totaled $351 million.
- Unit operating cost (reflecting costs from direct operations,
transportation, production taxes, and G&A) totaled $8.89 per
BOE (barrel of oil equivalent), near the mid-point of our annual
guidance range of $7.45 to $9.55 per BOE.
- Total equivalent production of 682 MBoepd (thousand barrels of
oil equivalent per day), exceeded the high end of guidance (630 to
660 MBoepd), driven by improved cycle times and strong well
performance.
- Oil production averaged 113.0 MBopd (thousand barrels of oil
per day), exceeding the high end of guidance (106 to 110
MBopd).
- Natural gas production averaged 2,779 MMcfpd (million cubic
feet per day), exceeding the high end of guidance (2,530 to 2,660
MMcfpd).
- Natural Gas Liquids (NGLs) production averaged 105.4
MBoepd.
- Oil was $68.57 per barrel (Bbl), excluding the effect of
commodity derivatives, and $68.70 per Bbl, including the effect of
commodity derivatives.
- Natural Gas was $2.02 per Mcf (thousand cubic feet), excluding
the effect of commodity derivatives, and $2.04 per Mcf, including
the effect of commodity derivatives.
- NGLs were $20.94 per BOE.
2025 Outlook (including the impact of acquisitions from their
closing dates in January)
- Estimate Discretionary Cash Flow (non-GAAP) of approximately
$5.0 billion and Free Cash Flow (non-GAAP) of approximately $2.7
billion, at recent strip prices.
- Expect 2025 capital expenditures of $2.1 to $2.4 billion, up
28% year-over-year at the mid-point, driven by incremental spend
associated with our recently completed Delaware Basin acquisitions.
The 2025 reinvestment rate (non-GAAP) is slightly below 50%, at the
recent strip. In 2025, the Company expects to average approximately
11 drilling rigs and 3 completion crews in the Permian Basin, 1 rig
and 0.5 completion crews in the Marcellus, and 1.5 drilling rigs
and 0.5 completion crews in the Anadarko Basin.
- Expect 2025 total equivalent production of 710 to 770 MBoepd,
up approximately 9% year-over-year at the mid-point; oil production
of 152 to 168 MBopd, up approximately 47% year-over-year at the
mid-point; and natural gas production of 2,675 to 2,875 MMcfpd,
relatively flat year-over-year at the mid-point.
- Expect 1Q25 total equivalent production of 710 to 750 MBoepd,
oil production of 134 to 144 MBopd, natural gas production of 2,850
to 3,000 MMcfpd, and capital expenditures of $525 to $625
million.
Three Year Outlook: 2025 to 2027
- Reflecting legacy Coterra growth in 2025 and pro forma growth
in 2026 and 2027, our new three-year outlook (2025 through 2027),
includes annual average oil growth of 5% or greater, annual average
BOE growth of 0 to 5%, which includes legacy organic Coterra growth
in 2025 and pro forma combined growth in 2026 and 2027, and an
average annual capital range of $2.1 to $2.4 billion. At the recent
strip, this would imply an average reinvestment rate (non-GAAP)
below 50% over the three-year period.
- The Company maintains significant flexibility to adjust its
total capital investment level and allocation of capital across its
three basins, supported by limited long-term service contracts and
minimal lease obligations. The Company maintains flexibility and
optionality in each of its three operating regions, allowing a
flexible allocation of capital to its highest return projects.
- We expect this three year outlook to deliver significant Free
Cash Flow (non-GAAP) to support our healthy base dividend, rapid
debt reduction, and an impactful share repurchase program.
Fourth Quarter and Full-Year 2024 Shareholder Return
Highlights
- Common Dividend: On February 24, 2025, Coterra's Board
of Directors (the "Board") approved a quarterly base dividend of
$0.22 per share, a 5% increase. The dividend will be paid on March
27, 2025 to holders of record on March 13, 2025.
- Share Repurchases: During the quarter, the Company
repurchased 2.1 million shares for $50 million (excluding 1% excise
tax) at a weighted-average price of $24.29 per share. During 2024,
the Company repurchased 17.1 million shares for $451 million at a
weighted-average price of $26.41 per share. $1.1 billion remains on
the Company's $2.0 billion share repurchase authorization as of
December 31, 2024.
- Total Shareholder Return: During the quarter, total
shareholder returns amounted to $218 million, composed of $168
million of declared dividends and $50 million of share repurchases
(excluding 1% excise tax). In 2024, total shareholder returns
amounted to $1,086 million, composed of $635 million of declared
dividends and $451 million of share repurchases (excluding 1%
excise tax), representing 89% of 2024 Free Cash Flow
(non-GAAP).
- Shareholder Return Strategy: Based on our current
outlook, Coterra expects to return 50% or more of its annual Free
Cash Flow (non-GAAP). In 2025, the Company intends to utilize a
significant portion of its Free Cash Flow (non-GAAP) for its base
dividend, the retirement of its term loans and share repurchases.
Coterra also expects to continue to review increasing its base
dividend on an annual cadence.
Full-Year 2024 Highlights
- Net Income (GAAP) totaled $1,121 million, or $1.51 per share.
Adjusted Net Income (non-GAAP) was $1,245 million, or $1.68 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $2,795
million. Discretionary Cash Flow (non-GAAP) totaled $2,968
million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $1,754 million. Capital
expenditures for drilling, completion and other fixed asset
additions (non-GAAP) totaled $1,762 million, at the low end of our
original guidance range of $1.75 to $1.95 billion.
- Free Cash Flow (non-GAAP) totaled $1,214 million. Unit
operating costs (reflecting costs from direct operations,
transportation, production taxes, and G&A) totaled $8.66 per
BOE, within our annual guidance range of $7.45 to $9.55 per
BOE.
- Total equivalent production of 677 MBoepd, exceeded the high
end of our original guidance (635 to 675 MBoepd), driven by
improved cycle times and strong well performance.
- Oil production averaged 108.8 MBopd, exceeding the high end of
original guidance (99 to 105 MBopd).
- Natural gas production averaged 2,800 MMcfpd, exceeding the
high end of original guidance (2,650 to 2,800 MMcfpd).
- NGLs production averaged 101.1 MBoepd.
- Oil: $74.18 per Bbl, excluding the effect of commodity
derivatives, and $74.22 per Bbl, including the effect of commodity
derivatives
- Natural Gas: $1.65 per Mcf, excluding the effect of commodity
derivatives, and $1.75 per Mcf, including the effect of commodity
derivatives
Strong Financial Position
The Company ended the year with a cash balance of $2.0 billion,
two undrawn $500 million term loans totaling $1.0 billion, and no
debt outstanding under its $2.0 billion revolving credit facility,
resulting in total liquidity of approximately $5.0 billion.
Coterra's net debt to trailing twelve-month EBITDAX ratio
(non-GAAP) at December 31, 2024 was 0.4x.
In January 2025, we closed on our Delaware Basin acquisitions,
which, after purchase price adjustments, included total cash
consideration of approximately $3.2 billion and stock consideration
to the sellers totaling 28.2 million Coterra common shares. Due to
purchase price adjustments, which were calculated based on
Coterra's share price at the time the acquisitions were announced,
of $24.24 per share, 28.2 million shares were issued, down from
40.9 million shares anticipated to be issued at announcement of the
transactions. Based on our current outlook, Coterra expects to
retire its term loans totaling $1.0 billion in 2025 and expects to
maintain a Net Debt to Adjusted EBITDAX leverage ratio (non-GAAP)
below 1.0x, through commodity price cycles.
See “Supplemental Non-GAAP Financial Measures” below for
descriptions of the above non-GAAP measures as well as
reconciliations of these measures to the associated GAAP
measures.
2024 Proved Reserves
At December 31, 2024, Coterra's proved reserves totaled 2,271
million barrels of oil equivalent (MMBoe), down approximately 2%
year-over-year. This was primarily driven by lower trailing 12
months natural gas prices and the decision to book fewer proved
undeveloped reserves. At year-end 2024 proved undeveloped reserves
were 18% of total proved reserves, down from 21% at year-end 2023.
The proved undeveloped percentage reduction allows management to
maintain future budgeting flexibility and the ability to allocate
future capital to its most productive use between its business
units.
Proved developed producing reserves were up 1% year over
year.
SEC realized commodity prices used to calculate our proved
reserves in 2024 for oil, natural gas liquids and natural gas,
adjusted for basis and quality differentials, are $72.84 per Bbl,
$18.16 per Bbl and $1.23 per Mcf, respectively, down from 2023
prices of $75.05 per Bbl, $18.39 per Bbl and $2.04 per Mcf.
The Company had net positive revisions of prior estimates of 9
MMBoe. This revision included a 59 MMBoe negative revision due to
price, offset by a positive 64 MMBoe performance revision and a 4
MMBoe positive revision for improved operating expenses.
For a summary of Coterra's estimated proved reserves at December
31, 2024, see the "Year-End Proved Reserves" table below and in our
annual report on Form 10-K for the fiscal year ended December 31,
2024.
Committed to Sustainability and ESG Leadership
Coterra is committed to environmental stewardship, sustainable
practices, and strong corporate governance. The Company's
sustainability report can be found under "ESG" on
www.coterra.com.
Conference Call
Coterra will host a conference call tomorrow, Tuesday, February
25, 2025, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter
and full-year 2024 financial and operating results and its 2025
outlook.
Conference Call Information
Date: Tuesday, February 25, 2025
Time: 9:00 AM CT / 10:00 AM ET
Dial-in (for callers in the U.S. and Canada): (800) 715-9871
International dial-in: (646) 307-1963
Conference ID: 4460734
The live audio webcast and related earnings presentation can be
accessed on the "Events & Presentations" page under the
"Investors" section of the Company's website at www.coterra.com.
The webcast will be archived and available at the same location
after the conclusion of the live event.
About Coterra Energy
Coterra is a premier exploration and production company based in
Houston, Texas with focused operations in the Permian Basin,
Marcellus Shale, and Anadarko Basin. We strive to be a leading
energy producer, delivering sustainable returns through the
efficient and responsible development of our diversified asset
base. Learn more about us at www.coterra.com.
Cautionary Statement Regarding Forward-Looking
Information
This press release contains certain forward-looking statements
within the meaning of federal securities laws. Forward-looking
statements are not statements of historical fact and reflect
Coterra's current views about future events. Such forward-looking
statements include, but are not limited to, statements about
returns to shareholders (including anticipated future dividend
increases), enhanced shareholder value, reserves estimates, future
financial and operating performance, and goals and commitment to
sustainability and ESG leadership, strategic pursuits and goals,
including with respect to the publication of Coterra’s
Sustainability Report, and other statements that are not historical
facts contained in this press release. The words "expect,"
"project," "estimate," "believe," "anticipate," "intend," "budget,"
"plan," "predict," "potential," "possible," "may," "should,"
"could," "would," "will," "strategy," "outlook", "guide" and
similar expressions are also intended to identify forward-looking
statements. We can provide no assurance that the forward-looking
statements contained in this press release will occur as projected
and actual results may differ materially from those projected.
Forward-looking statements are based on current expectations,
estimates and assumptions that involve a number of risks and
uncertainties that could cause actual results to differ materially
from those projected. These risks and uncertainties include,
without limitation, the volatility in commodity prices for crude
oil and natural gas; cost increases; the effect of future
regulatory or legislative actions; the impact of public health
crises, including pandemics (such as the coronavirus pandemic) and
epidemics and any related governmental policies or actions on
Coterra’s business, financial condition and results of operations;
actions by, or disputes among or between, the Organization of
Petroleum Exporting Countries and other producer countries; market
factors; market prices (including geographic basis differentials)
of oil and natural gas; impacts of inflation; labor shortages and
economic disruption (including as a result of geopolitical
disruptions such as the war in Ukraine or conflict in the Middle
East); determination of reserves estimates, adjustments or
revisions, including factors impacting such determination such as
commodity prices, well performance, operating expenses and
completion of Coterra’s annual PUD reserves process, as well as the
impact on our financial statements resulting therefrom; the
presence or recoverability of estimated reserves; the ability to
replace reserves; environmental risks; drilling and operating
risks; exploration and development risks; competition; the ability
of management to execute its plans to meet its goals (including
successful integration of the Delaware Basin acquisitions into
Coterra's operations); and other risks inherent in Coterra's
businesses. In addition, the declaration and payment of any future
dividends (or any increases thereto), whether regular base
quarterly dividends, variable dividends or special dividends, as
well as any share repurchases or pay downs of existing debt, will
depend on Coterra's financial results, cash requirements, future
prospects and other factors deemed relevant by Coterra's Board.
While the list of factors presented here is considered
representative, no such list should be considered to be a complete
statement of all potential risks and uncertainties. Should one or
more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary
materially from those indicated. For additional information about
other factors that could cause actual results to differ materially
from those described in the forward-looking statements, please
refer to Coterra's annual reports on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K and other filings with
the SEC, which are available on Coterra's website at
www.coterra.com.
Forward-looking statements are based on the estimates and
opinions of management at the time the statements are made. Except
to the extent required by applicable law, Coterra does not
undertake any obligation to publicly update or revise any
forward-looking statement, whether as a result of new information,
future events or otherwise. Readers are cautioned not to place
undue reliance on these forward-looking statements that speak only
as of the date hereof.
Operational Data
The tables below provide a summary of production volumes, price
realizations and operational activity by region and units costs for
the Company for the periods indicated:
Quarter Ended December
31,
Twelve Months Ended
December 31,
2024
2023
2024
2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)
2,042.8
2,304.9
2,098.5
2,262.7
Daily equivalent production (MBoepd)
340.5
384.2
349.7
377.1
Permian Basin
Natural gas (Mmcf/day)
517.5
482.0
505.1
440.8
Oil (MBbl/day)
103.8
97.3
100.8
89.5
NGL (MBbl/day)
78.3
76.9
77.3
70.5
Daily equivalent production (MBoepd)
268.3
254.5
262.2
233.4
Anadarko Basin
Natural gas (Mmcf/day)
217.2
179.4
194.3
178.9
Oil (MBbl/day)
9.1
6.7
7.9
6.5
NGL (MBbl/day)
27.1
20.7
23.7
19.7
Daily equivalent production (MBoepd)
72.4
57.3
64.0
56.0
Total Company
Natural gas (Mmcf/day)
2,778.9
2,970.0
2,799.8
2,884.2
Oil (MBbl/day)
113.0
104.7
108.8
96.2
NGL (MBbl/day)
105.4
97.8
101.1
90.2
Daily equivalent production (MBoepd)
681.5
697.4
676.5
667.1
AVERAGE SALES PRICE (excluding
hedges)
Marcellus Shale
Natural gas ($/Mcf)
$
2.27
$
2.17
$
1.98
$
2.33
Permian Basin
Natural gas ($/Mcf)
$
0.79
$
1.19
$
0.16
$
1.28
Oil ($/Bbl)
$
68.55
$
77.26
$
74.18
$
75.98
NGL ($/Bbl)
$
20.00
$
17.65
$
19.13
$
18.44
Anadarko Basin
Natural gas ($/Mcf)
$
2.51
$
2.30
$
1.92
$
2.37
Oil ($/Bbl)
$
68.80
$
79.12
$
74.16
$
76.92
NGL ($/Bbl)
$
23.66
$
22.40
$
22.62
$
23.54
Total Company
Natural gas ($/Mcf)
$
2.02
$
2.03
$
1.65
$
2.18
Oil ($/Bbl)
$
68.57
$
77.10
$
74.18
$
75.97
NGL ($/Bbl)
$
20.94
$
18.66
$
19.95
$
19.56
Quarter Ended December
31,
Twelve Months Ended
December 31,
2024
2023
2024
2023
AVERAGE SALES PRICE (including
hedges)
Total Company
Natural gas ($/Mcf)
$
2.04
$
2.19
$
1.75
$
2.44
Oil ($/Bbl)
$
68.70
$
77.21
$
74.22
$
76.07
NGL ($/Bbl)
$
20.94
$
18.66
$
19.95
$
19.56
Quarter Ended December
31,
Twelve Months Ended
December 31,
2024
2023
2024
2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale
—
20
26
73
Permian Basin
56
44
230
159
Anadarko Basin
18
2
57
32
74
66
313
264
Net wells
Marcellus Shale
—
16.2
25.0
69.2
Permian Basin
35.3
18.6
111.3
82.1
Anadarko Basin
3.2
1.8
23.1
18.1
38.5
36.6
159.4
169.4
TURN IN LINES
Gross wells
Marcellus Shale
11
12
41
71
Permian Basin
36
61
195
183
Anadarko Basin
17
3
58
19
64
76
294
273
Net wells
Marcellus Shale
11.0
12.0
41.0
71.0
Permian Basin
18.1
28.0
86.5
94.9
Anadarko Basin
5.6
—
25.5
7.1
34.7
40.0
153.0
173.0
AVERAGE RIG COUNTS
Marcellus Shale
—
2.0
0.9
2.6
Permian Basin
8.7
7.0
8.2
6.5
Anadarko Basin
1.0
1.0
1.3
1.3
Quarter Ended December
31,
Twelve Months Ended
December 31,
2024
2023
2024
2023
AVERAGE UNIT COSTS ($/Boe)(2)
Direct operations
$
2.83
$
2.51
$
2.66
$
2.31
Gathering, processing and
transportation
3.82
3.83
3.94
4.00
Taxes other than income
1.22
1.12
1.09
1.16
General and administrative (excluding
stock-based compensation and severance expense)
1.02
0.95
0.97
0.90
Unit Operating Cost
$
8.89
$
8.41
$
8.66
$
8.37
Depreciation, depletion and
amortization
7.75
7.11
7.43
6.74
Exploration
0.09
0.08
0.10
0.08
Stock-based compensation
0.29
0.23
0.25
0.24
Severance expense
—
0.03
—
0.05
Interest expense
0.29
0.13
0.18
0.11
$
17.31
$
16.00
$
16.62
$
15.60
_______________________________________________________________________________
(1)
Wells drilled represents wells drilled to total depth during the
period. Wells completed includes wells completed during the period,
regardless of when they were drilled.
(2)
Total unit costs may differ from the sum of the individual costs
due to rounding.
Derivatives Information
As of December 31, 2024, the Company had the following
outstanding financial commodity derivatives:
2025
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
5,040
5,096
4,232
4,232
Weighted average floor ($/Bbl)
$
61.79
$
61.79
$
61.63
$
61.63
Weighted average ceiling ($/Bbl)
$
79.36
$
79.36
$
78.64
$
78.64
WTI Midland oil basis swaps
Volume (MBbl)
6,300
6,370
5,520
5,520
Weighted average differential ($/Bbl)
$
1.07
$
1.07
$
1.02
$
1.02
WTI oil swaps
Volume (MBbl)
1,710
1,729
1,748
1,748
Weighted average price ($/Bbl)
69.18
69.18
69.18
69.18
2026
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
900
910
920
920
Weighted average floor ($/Bbl)
$
62.50
$
62.50
$
62.50
$
62.50
Weighted average ceiling ($/Bbl)
$
69.40
$
69.40
$
69.40
$
69.40
WTI Midland oil basis swaps
Volume (MBbl)
1,800
1,820
1,840
1,840
Weighted average differential ($/Bbl)
$
0.95
$
0.95
$
0.95
$
0.95
WTI oil swaps
Volume (MBbl)
900
910
920
920
Weighted average price ($/Bbl)
$
66.14
$
66.14
$
66.14
$
66.14
2025
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX Collars
Volume (MMBtu)
45,000,000
45,500,000
46,000,000
46,000,000
Weighted average floor ($/MMBtu)
$
2.85
$
2.85
$
2.85
$
2.85
Weighted average ceiling ($/MMBtu)
$
4.51
$
4.07
$
4.07
$
5.55
Transco Leidy gas basis swaps
Volume (MMBtu)
18,000,000
18,200,000
18,400,000
18,400,000
Weighted average price ($/MMBtu)
$
(0.70
)
$
(0.70
)
$
(0.70
)
$
(0.70
)
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)
9,000,000
9,100,000
9,200,000
9,200,000
Weighted average price ($/MMBtu)
$
(0.29
)
$
(0.29
)
$
(0.29
)
$
(0.29
)
2026
Natural Gas
First Quarter
NYMEX Collars
Volume (MMBtu)
27,000,000
Weighted average floor ($/MMBtu)
$
2.75
Weighted average ceiling ($/MMBtu)
$
7.66
In January 2025, the Company entered into
the following financial commodity derivatives:
2025
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
5,900,000
9,100,000
9,200,000
9,200,000
Weighted average floor ($/MMBtu)
$
3.00
$
3.00
$
3.00
$
3.00
Weighted average ceiling ($/MMBtu)
$
4.46
$
4.46
$
4.46
$
4.46
2026
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
22,500,000
22,750,000
23,000,000
23,000,000
Weighted average floor ($/MMBtu)
$
3.00
$
3.00
$
3.00
$
3.00
Weighted average ceiling ($/MMBtu)
$
5.79
$
5.79
$
5.79
$
5.79
Year-End Proved Reserves
The tables below provide a summary of changes in proved reserves
for the year ended December 31, 2024.
Oil (MBbl)
Natural Gas
(Bcf)
NGL (MBbl)
Total (MBOE)
PROVED RESERVES
December 31, 2023
249,213
10,525
317,456
2,320,757
Revision of previous estimates
11,636
(181
)
27,686
9,039
Extensions and discoveries
48,956
516
53,628
188,516
Production
(39,808
)
(1,025
)
(36,993
)
(247,589
)
Sales of reserves
(2
)
(1
)
—
(2
)
December 31, 2024
269,995
9,834
361,777
2,270,721
PROVED DEVELOPED RESERVES
December 31, 2023
173,392
8,590
234,306
1,839,219
December 31, 2024
189,275
8,420
271,030
1,863,583
CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In millions,
except per share amounts)
2024
2023
2024
2023
OPERATING REVENUES
Oil
$
713
$
742
$
2,953
$
2,667
Natural gas
516
553
1,693
2,292
NGL
203
168
738
644
Gain (loss) on derivative instruments
(51
)
101
(3
)
230
Other
14
32
77
81
1,395
1,596
5,458
5,914
OPERATING EXPENSES
Direct operations
177
161
658
562
Gathering, processing and
transportation
239
246
976
975
Taxes other than income
77
72
271
283
Exploration
6
6
25
20
Depreciation, depletion and
amortization
486
456
1,840
1,641
General and administrative (excluding
stock-based compensation and severance expense)
65
61
240
220
Stock-based compensation(1)
19
15
62
59
Severance expense
—
2
—
12
1,069
1,019
4,072
3,772
Gain (loss) on sale of assets
—
—
3
12
INCOME FROM OPERATIONS
326
577
1,389
2,154
Interest expense
29
23
106
73
Interest income
(11
)
(15
)
(62
)
(47
)
Income before income taxes
308
569
1,345
2,128
Income tax provision (benefit)
Current
96
97
369
428
Deferred
(85
)
56
(145
)
75
Total Income tax provision
11
153
224
503
NET INCOME
$
297
$
416
$
1,121
$
1,625
Earnings per share - Basic
$
0.40
$
0.55
$
1.51
$
2.14
Weighted-average common shares
outstanding
736
751
742
756
_______________________________________________________________________________
(1) Includes the impact of our
performance share awards and restricted stock.
CONDENSED CONSOLIDATED BALANCE
SHEET (Unaudited)
(In
millions)
December 31,
2024
December 31,
2023
ASSETS
Current assets
$
3,321
$
2,015
Properties and equipment, net (successful
efforts method)
17,890
17,933
Other assets
414
467
$
21,625
$
20,415
LIABILITIES, REDEEMABLE PREFERRED STOCK
AND STOCKHOLDERS' EQUITY
Current liabilities
$
1,136
$
1,085
Current portion of long-term debt
—
575
Long-term debt, net (excluding current
maturities)
3,535
1,586
Deferred income taxes
3,274
3,413
Other long term liabilities
550
709
Cimarex redeemable preferred stock
8
8
Stockholders’ equity
13,122
13,039
$
21,625
$
20,415
CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In
millions)
2024
2023
2024
2023
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income
$
297
$
416
$
1,121
$
1,625
Depreciation, depletion and
amortization
486
456
1,840
1,641
Deferred income tax expense
(85
)
55
(145
)
74
(Gain) loss on sale of assets
—
—
(3
)
(12
)
Exploratory dry hole cost
—
—
5
—
(Gain) loss on derivative instruments
51
(101
)
3
(230
)
Net cash received (paid) in settlement of
derivative instruments
8
46
98
284
Stock-based compensation and other
18
14
61
57
Income charges not requiring cash
1
(5
)
(12
)
(18
)
Changes in assets and liabilities
(150
)
(121
)
(173
)
237
Net cash provided by operating
activities
626
760
2,795
3,658
CASH FLOWS FROM INVESTING
ACTIVITIES
Capital expenditures for drilling,
completion and other fixed asset additions
(425
)
(468
)
(1,754
)
(2,089
)
Capital expenditures for leasehold and
property acquisitions
(11
)
(2
)
(17
)
(10
)
Proceeds from sale of assets
1
—
9
40
Proceeds from sale of short-term
investments
—
—
250
—
Purchase of short-term investments
—
—
(250
)
—
Net cash used in investing activities
(435
)
(470
)
(1,762
)
(2,059
)
CASH FLOWS FROM FINANCING
ACTIVITIES
Net borrowings (repayments) of debt
1,491
—
1,415
—
Common stock repurchases
(54
)
(20
)
(455
)
(405
)
Dividends paid
(155
)
(151
)
(625
)
(890
)
Capitalized debt issuance costs
(33
)
(7
)
(33
)
(7
)
Other
(11
)
(3
)
(23
)
(15
)
Net cash provided by (used in) financing
activities
1,238
(181
)
279
(1,317
)
Net increase (decrease) in cash, cash
equivalents and restricted cash
$
1,429
$
109
$
1,312
$
282
Supplemental Non-GAAP Financial Measures
(Unaudited)
We report our financial results in accordance with accounting
principles generally accepted in the United States (GAAP). However,
we believe certain non-GAAP performance measures may provide
financial statement users with additional meaningful comparisons
between current results and results of prior periods. In addition,
we believe these measures are used by analysts and others in the
valuation, rating and investment recommendations of companies
within the oil and natural gas exploration and production industry.
See the reconciliations below that compare GAAP financial measures
to non-GAAP financial measures for the periods indicated.
We have also included herein certain forward-looking non-GAAP
financial measures, including, among others, the reinvestment rate,
which is defined as capital expenditures (non-GAAP) as a percentage
of Discretionary Cash Flow (non-GAAP). We believe the reinvestment
rate provides investors with useful information on management's
projected use and reinvestment of its future cash flows back into
Coterra's operations. Due to the forward-looking nature of these
non-GAAP financial measures, we cannot reliably predict certain of
the necessary components of the most directly comparable
forward-looking GAAP measures, including changes in assets and
liabilities (including future impairments) and cash paid for
certain capital expenditures. Accordingly, we are unable to present
a quantitative reconciliation of such forward-looking non-GAAP
financial measures to their most directly comparable
forward-looking GAAP financial measures. Reconciling items in
future periods could be significant.
Reconciliation of Net Income to Adjusted Net
Income and Adjusted Earnings Per Share
Adjusted Net Income and Adjusted Earnings per Share are
presented based on our management's belief that these non-GAAP
measures enable a user of financial information to understand the
impact of identified adjustments on reported results. Adjusted Net
Income is defined as net income plus gain and loss on sale of
assets, non-cash gain and loss on derivative instruments,
stock-based compensation expense, severance expense, merger-related
expenses and tax effect on selected items. Adjusted Earnings per
Share is defined as Adjusted Net Income divided by weighted-average
common shares outstanding. Additionally, we believe these measures
provide beneficial comparisons to similarly adjusted measurements
of prior periods and use these measures for that purpose. Adjusted
Net Income and Adjusted Earnings per Share are not measures of
financial performance under GAAP and should not be considered as
alternatives to net income and earnings per share, as defined by
GAAP.
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In millions,
except per share amounts)
2024
2023
2024
2023
As reported - net income
$
297
$
416
$
1,121
$
1,625
Reversal of selected items:
(Gain) loss on sale of assets
—
—
(3
)
(12
)
(Gain) loss on derivative
instruments(1)
59
(55
)
101
54
Stock-based compensation expense
19
15
62
59
Severance expense
—
2
—
12
Tax effect on selected items
(17
)
9
(36
)
(26
)
Adjusted net income
$
358
$
387
$
1,245
$
1,712
As reported - earnings per share
$
0.40
$
0.55
$
1.51
$
2.14
Per share impact of selected items
0.09
(0.03
)
0.17
0.12
Adjusted earnings per share
$
0.49
$
0.52
$
1.68
$
2.26
Weighted-average common shares
outstanding
736
751
742
756
_______________________________________________________________________________
(1)
This amount represents the non-cash mark-to-market changes of
our commodity derivative instruments recorded in Gain (loss) on
derivative instruments in the Condensed Consolidated Statement of
Operations.
Reconciliation of Discretionary Cash Flow
and Free Cash Flow
Discretionary Cash Flow is defined as cash flow from operating
activities excluding changes in assets and liabilities.
Discretionary Cash Flow is widely accepted as a financial indicator
of an oil and gas company’s ability to generate available cash to
internally fund exploration and development activities, return
capital to shareholders through dividends and share repurchases,
and service debt and is used by our management for that purpose.
Discretionary Cash Flow is presented based on our management’s
belief that this non-GAAP measure is useful information to
investors when comparing our cash flows with the cash flows of
other companies that use the full cost method of accounting for oil
and gas producing activities or have different financing and
capital structures or tax rates. Discretionary Cash Flow is not a
measure of financial performance under GAAP and should not be
considered as an alternative to cash flows from operating
activities or net income, as defined by GAAP, or as a measure of
liquidity.
Free Cash Flow is defined as Discretionary Cash Flow less cash
paid for capital expenditures. Free Cash Flow is an indicator of a
company’s ability to generate cash flow after spending the money
required to maintain or expand its asset base, and is used by our
management for that purpose. Free Cash Flow is presented based on
our management’s belief that this non-GAAP measure is useful
information to investors when comparing our cash flows with the
cash flows of other companies. Free Cash Flow is not a measure of
financial performance under GAAP and should not be considered as an
alternative to cash flows from operating activities or net income,
as defined by GAAP, or as a measure of liquidity.
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In
millions)
2024
2023
2024
2023
Cash flow from operating activities
$
626
$
760
$
2,795
$
3,658
Changes in assets and liabilities
150
121
173
(237
)
Discretionary cash flow
776
881
2,968
3,421
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions
(425
)
(468
)
(1,754
)
(2,089
)
Free cash flow
$
351
$
413
$
1,214
$
1,332
Capital Expenditures
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In
millions)
2024
2023
2024
2023
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions
$
425
$
468
$
1,754
$
2,089
Change in accrued capital costs
(8
)
(11
)
3
15
Exploratory dry-hole cost
—
—
5
—
Capital expenditures
$
417
$
457
$
1,762
$
2,104
Reconciliation of Adjusted EBITDAX
Adjusted EBITDAX is defined as net income plus interest expense,
other expense, income tax expense, depreciation, depletion, and
amortization (including impairments), exploration expense, gain and
loss on sale of assets, non-cash gain and loss on derivative
instruments, stock-based compensation expense, severance expense
and merger-related expense. Adjusted EBITDAX is presented on our
management’s belief that this non-GAAP measure is useful
information to investors when evaluating our ability to internally
fund exploration and development activities and to service or incur
debt without regard to financial or capital structure. Our
management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX
is not a measure of financial performance under GAAP and should not
be considered as an alternative to cash flows from operating
activities or net income, as defined by GAAP, or as a measure of
liquidity.
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In
millions)
2024
2023
2024
2023
Net income
$
297
$
416
$
1,121
$
1,625
Plus (less):
Interest expense
29
23
106
73
Interest income
(11
)
(15
)
(62
)
(47
)
Income tax expense
11
153
224
503
Depreciation, depletion and
amortization
486
456
1,840
1,641
Exploration
6
6
25
20
(Gain) loss on sale of assets
—
—
(3
)
(12
)
Non-cash (gain) loss on derivative
instruments
59
(55
)
101
54
Stock-based compensation
19
15
62
59
Severance expense
—
2
—
12
Adjusted EBITDAX
$
896
$
1,001
$
3,414
$
3,928
Reconciliation of Net Debt
The total debt to total capitalization ratio is calculated by
dividing total debt by the sum of total debt and total
stockholders’ equity. This ratio is a measurement which is
presented in our annual and interim filings and our management
believes this ratio is useful to investors in assessing our
leverage. Net Debt is calculated by subtracting cash and cash
equivalents from total debt. The Net Debt to Adjusted
Capitalization ratio is calculated by dividing Net Debt by the sum
of Net Debt and total stockholders’ equity. Net Debt and the Net
Debt to Adjusted Capitalization ratio are non-GAAP measures which
our management believes are also useful to investors when assessing
our leverage since we have the ability to and may decide to use a
portion of our cash and cash equivalents to retire debt. Our
management uses these measures for that purpose. Additionally, as
our planned expenditures are not expected to result in additional
debt, our management believes it is appropriate to apply cash and
cash equivalents to reduce debt in calculating the Net Debt to
Adjusted Capitalization ratio.
(In
millions)
December 31,
2024
December 31,
2023
Current portion of long-term debt
$
—
$
575
Long-term debt, net
3,535
$
1,586
Total debt
$
3,535
$
2,161
Stockholders’ equity
13,122
13,039
Total capitalization
$
16,657
$
15,200
Total debt
$
3,535
$
2,161
Less: Cash and cash equivalents
(2,038
)
(956
)
Net debt
$
1,497
$
1,205
Net debt
$
1,497
$
1,205
Stockholders’ equity
13,122
13,039
Total adjusted capitalization
$
14,619
$
14,244
Total debt to total capitalization
ratio
21.2
%
14.2
%
Less: Impact of cash and cash
equivalents
11.0
%
5.7
%
Net debt to adjusted capitalization
ratio
10.2
%
8.5
%
Reconciliation of Net Debt to Adjusted
EBITDAX
Total debt to net income is defined as total debt divided by net
income. Net debt to Adjusted EBITDAX is defined as net debt divided
by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted
EBITDAX is a non-GAAP measure which our management believes is
useful to investors when assessing our credit position and
leverage.
(In
millions)
December 31,
2024
December 31,
2023
Total debt
$
3,535
$
2,161
Net income
1,121
$
1,625
Total debt to net income ratio
3.2 x
1.3 x
Net debt (as defined above)
$
1,497
$
1,205
Adjusted EBITDAX (Twelve months ended
December 31)
3,414
3,928
Net debt to Adjusted EBITDAX
0.4 x
0.3 x
2025 Guidance
The tables below present full-year and first quarter 2025
guidance.
Full Year Guidance
2024 Guidance
2024 Actual
2025 Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
660
668
675
677
710
740
770
Gas (Mmcf/day)
2,735
2,755
2,775
2,800
2,675
2,775
2,875
Oil (MBbl/day)
107
108
108
108.8
152
160
168
Net wells turned in line
Marcellus Shale
40
41
10
13
15
Permian Basin
80
85
90
87
150
158
165
Anadarko Basin
21
24
27
26
15
20
25
Incurred capital expenditures ($ in
millions)
Total Company
$1,750
$1,800
$1,850
$1,762
$2,100
$2,250
$2,400
Drilling and completion
Marcellus Shale
$300 midpoint
$286
$250 midpoint
Permian Basin
$1,050 midpoint
$1,051
$1,570 midpoint
Anadarko Basin
$300 midpoint
$287
$230 midpoint
Midstream, saltwater disposal and
infrastructure
$150 midpoint
$137
$200 midpoint
First Quarter Guidance
Fourth Quarter 2024
Guidance
Fourth Quarter 2024
Actual
First Quarter 2025
Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
630
645
660
682
710
730
750
Gas (Mmcf/day)
2,530
2,595
2,660
2,779
2,850
2,925
3,000
Oil (MBbl/day)
106
108
110
113
134
139
144
Net wells turned in line
Marcellus Shale
11
11
0
Permian Basin
13
18
23
18.1
35
40
45
Anadarko Basin
1
4
7
5.6
0
Incurred capital expenditures ($ in
millions)
Total Company
$410
$455
$500
$417
$525
$575
$625
View source
version on businesswire.com: https://www.businesswire.com/news/home/20250224266260/en/
Investor Contact Daniel Guffey - VP - Finance, IR,
& Treasurer 281.589.4875
Hannah Stuckey - Investor Relations Manager
281.589.4983
Coterra Energy (NYSE:CTRA)
Historical Stock Chart
From Jan 2025 to Feb 2025
Coterra Energy (NYSE:CTRA)
Historical Stock Chart
From Feb 2024 to Feb 2025
