Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the
“Company”) today reported fourth-quarter and full-year 2023
results, provided first-quarter and full-year 2024 guidance and
released a new three-year outlook for 2024 through 2026. The
Company also declared a quarterly dividend of $0.21 per share, a 5%
increase year-over-year.
Key Takeaways & Updates
- For the fourth quarter of 2023, total barrels of oil equivalent
and oil production beat the high-end of guidance and incurred
capital expenditures (non-GAAP) came in below the low-end of
guidance.
- Relative to our initial full-year 2023 guidance, total barrels
of oil equivalent and oil production beat the high-end of guidance
by 3% and 5%, respectively, and incurred capital expenditures
(non-GAAP) came in at the mid-point of guidance.
- Shareholder returns totaled 77% of 2023 Free Cash Flow
(non-GAAP). The Company remains committed to returning 50%+ of its
annual Free Cash Flow (non-GAAP) to shareholders.
- Declared $0.21 per share dividend for the fourth quarter of
2023, or $0.84 per share annualized, representing a 5% increase
year-over-year, and equating to a 3.2% yield, based on the
Company's $26.16 closing share price as of February 21, 2024.
- 2024 incurred capital expenditures (non-GAAP) are expected to
be between $1.75 and $1.95 billion, down 12% year-over-year at the
mid-point driven by lower Marcellus activity and expected cost
reductions. 2024 total barrel of oil equivalent production is
expected to be down approximately 2% year-over-year at the
mid-point, with oil volumes up approximately 6% and natural gas
volumes down approximately 6%, at the mid-point.
- New three-year outlook (2024 through 2026), guiding to 0-5%
barrel of oil equivalent and 5+% oil CAGRs, based on annual
incurred capital expenditures (non-GAAP) averaging between
$1.75-$1.95 billion.
Tom Jorden, Chairman, CEO and President of Coterra, noted,
“Coterra’s outstanding 2023 results were driven by our commitment
to operational excellence, coupled with strong execution in the
field. The Company invested at the mid-point of capital guidance
and beat the high-end of production guidance, which was driven by a
combination of strong well productivity and field efficiency gains.
As we look ahead, our 2024 capital plan underscores Coterra’s
ability to pivot capital as fundamentals in the commodity markets
dictate. Our disciplined, economically driven approach reduces
total capital investment by roughly 12% year over year driven by
lower natural-gas focused investments partially offset by a modest
increase of investment in our liquids-rich basins. The company
maintains optionality to further pivot capital in the future,
should macro conditions warrant.”
Mr. Jorden continued, “Our new three-year outlook, which calls
for 0-5% BOE growth and 5+% oil growth at an average $1.75-$1.95
billion capital spend, underscores the Company’s ability to
continue to improve its capital efficiency. Capital discipline,
allocating capital to its most productive use, consistent,
profitable growth, and maintaining a fortress balance sheet are key
to Coterra’s investment strategy and allow us to provide a robust
shareholder return program through the cycles.”
Fourth-Quarter 2023 Highlights
- Net Income (GAAP) totaled $416 million, or $0.55 per share.
Adjusted Net Income (non-GAAP) was $387 million, or $0.52 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $760
million. Discretionary Cash Flow (non-GAAP) totaled $881
million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $468 million. Incurred
capital expenditures for drilling, completion and other fixed asset
additions (non-GAAP) totaled $457 million, below the low end of our
guidance range of $460 to $530 million.
- Free Cash Flow (non-GAAP) totaled $413 million.
- Unit operating cost (reflecting costs from direct operations,
transportation, production taxes, and G&A) totaled $8.41 per
BOE (barrel of oil equivalent), within our annual guidance range
set at $7.30-$9.40 per BOE.
- Total equivalent production of 697 MBoepd (thousand barrels of
oil equivalent per day), exceeded the high end of guidance (645 to
680 MBoepd), driven by improved cycle times and strong well
performance.
- Oil production averaged 104.7 MBopd (thousand barrels of oil
per day), exceeding the high end of guidance (98 - 102 MBopd).
- Natural gas production averaged 2,970 MMcfpd (million cubic
feet per day), exceeding the high end of guidance (2,780 to 2,900
MMcfpd).
- Natural Gas Liquids (NGLs) production averaged 97.8
MBoepd.
- Realized average prices:
- Oil was $77.10 per barrel (Bbl), excluding the effect of
commodity derivatives, and $77.21 per Bbl, including the effect of
commodity derivatives.
- Natural Gas was $2.03 per Mcf (thousand cubic feet), excluding
the effect of commodity derivatives, and $2.19 per Mcf, including
the effect of commodity derivatives.
- NGLs were $18.66 per BOE.
2024 Outlook
- Estimate Discretionary Cash Flow (non-GAAP) of approximately
$3.15 billion and Free Cash Flow (non-GAAP) of approximately $1.3
billion, at approximately flat $75/bbl and $2.50/mmbtu
pricing.
- Expect 2024 incurred capital expenditures (non-GAAP) of $1.75 -
$1.95 billion
- Mid-point down approximately $250 million relative to 2023,
primarily due to lower Marcellus spending and lower service cost
expectations.
- Modestly increasing Permian and Anadarko capital
expenditures.
- Total Marcellus drilling and completion capital expenditures
estimated to be approximately $350 - 400 million, down
approximately 55% or approximately $460 million year-over-year at
the mid-point. As a result, Marcellus volumes are expected to be
down 6% year-over-year.
- Expect 2024 total equivalent production of 635-675 MBoepd, down
approximately 2% year-over-year at the mid-point; oil production of
99-105 MBopd, up approximately 6% year-over-year at the mid-point;
and natural gas production of 2,650 - 2,800 MMcfpd, down
approximately 6% year-over-year at the mid-point.
- Expect 1Q24 total equivalent production of 660 to 690 MBoepd,
oil production of 95 to 99 MBopd, natural gas production of 2,850
to 2,950 MMcfpd, and capital expenditures of $460 to $540
million.
Three Year Outlook: 2024-2026
- New three-year outlook (2024 through 2026), guiding to 0-5%
barrel of oil equivalent and 5+% oil CAGRs, based on annual
incurred capital expenditures (non-GAAP) averaging between
$1.75-$1.95 billion.
- The Company maintains significant flexibility to adjust its
total capital investment level and allocation of capital across its
three basins. This flexibility is supported by limited long-term
service contracts. While the Company is choosing to lower natural
gas-directed activity in 2024, it maintains options that could
significantly grow natural gas volumes over the next three
years.
Full-Year 2023 and Fourth Quarter 2023 Shareholder Return
Highlights
- Common Dividend: On February 22, 2024, Coterra's Board
of Directors (the "Board") approved a quarterly base dividend of
$0.21 per share, which is a 5% increase year-over-year. The
dividend will be paid on March 28, 2024 to holders of record on
March 14, 2024.
- Share Repurchases: During the quarter, the Company
repurchased 1.1 million shares for $29 million at a
weighted-average price of $26.84 per share. During 2023, the
Company repurchased 17 million shares for $418 million (including
1% excise tax) at a weighted-average price of $25.01 per share.
$1.6 billion remains on the $2.0 billion share repurchase
authorization as of December 31, 2023.
- Total Shareholder Return: During the quarter, total
shareholder returns amounted to $187 million, composed of $158
million of declared dividends and $29 million of share repurchases.
In 2023, total shareholder returns amounted to $1,026 million,
composed of $612 million of declared dividends and $414 million of
share repurchases (excluding accrued excise tax), representing 77%
of 2023 Free Cash Flow (non-GAAP).
- Shareholder Return Strategy: Coterra reaffirms its
commitment to returning 50% or more of its annual Free Cash Flow
(non-GAAP) to shareholders primarily through its base dividends and
share repurchases.
Full-Year 2023 Highlights
- Net Income (GAAP) totaled $1,625 million, or $2.14 per share.
Adjusted Net Income (non-GAAP) was $1,712 million, or $2.26 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $3,658
million. Discretionary Cash Flow (non-GAAP) totaled $3,421
million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $2,089 million. Incurred
capital expenditures for drilling, completion and other fixed asset
additions (non-GAAP) totaled $2,104 million, in line with the
mid-point of our guidance range of $2.0 to $2.2 billion.
- Free Cash Flow (non-GAAP) totaled $1,332 million. Unit
operating cost (reflecting costs from direct operations,
transportation, production taxes, and G&A) totaled $8.37 per
BOE, within our annual guidance range of $7.30-$9.40 per BOE.
- Total equivalent production of 667 MBoepd, exceeded the high
end of initial guidance (610 to 650 MBoepd), driven by improved
cycle times and strong well performance.
- Oil production averaged 96.2 MBopd, exceeding the high end of
initial guidance (86 to 92 MBopd).
- Natural gas production averaged 2,884 MMcfpd, exceeding the
high end of initial guidance (2,700 to 2,850 MMcfpd).
- NGLs production averaged 90.2 MBoepd.
- Realized average prices:
- Oil: $75.97 per Bbl, excluding the effect of commodity
derivatives, and $76.07 per Bbl, including the effect of commodity
derivatives
- Natural Gas: $2.18 per Mcf, excluding the effect of commodity
derivatives, and $2.44 per Mcf, including the effect of commodity
derivatives
- NGLs: $19.56 per BOE
Strong Financial Position
As of December 31, 2023, Coterra had total debt of $2.161
billion with a principal amount of $2.075 billion, of which $575
million is due in September 2024. The Company ended the year with a
cash balance of $956 million and no debt outstanding under its
revolving credit facility, resulting in total liquidity of
approximately $2.46 billion. Coterra's net debt to trailing
twelve-month EBITDAX ratio (non-GAAP) at December 31, 2023 was
0.3x.
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.
2023 Proved Reserves
At December 31, 2023, Coterra's proved reserves totaled 2,321
million barrels of oil equivalent (MMBoe), down approximately 3%
year-over-year, primarily driven by lower year-over-year SEC
commodity prices. SEC commodity prices underpinning our proved
reserves in 2023 for oil, natural gas liquids and natural gas,
adjusted for basis and quality differentials, are $75.05 per Bbl,
$18.39 per Bbl and $2.04 per Mcf, respectively, down from 2022
prices of $94.21 per Bbl, $31.45 per Bbl and $5.25 per Mcf.
The Company had net negative revisions of prior estimates of 60
MMBoe which included an 83 MMBoe negative revision due to price and
a 10 MMBoe negative revision due to increases in operating
expenses, partially offset by a positive 33 MMBoe performance
revision. Excluding the SEC 5-year rule, there was a positive
technical revision in the Marcellus Shale.
At December 31, 2023, the company’s proved undeveloped reserves
were 21% of total proved reserves, down from 24% at year-end 2022.
This decrease was driven primarily by the company’s decision to
reduce proved undeveloped additions to provide more capital
investment flexibility across its three core operating regions.
For a summary of Coterra's estimated proved reserves at December
31, 2023, see the "Year-End Proved Reserves" table below and in our
annual report on Form 10-K for the fiscal year ended December 31,
2023.
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, Friday, February
23, 2024, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter
and full-year 2023 financial and operating results and its 2024
outlook.
Conference Call Information Date: Friday, February 23, 2024
Time: 9:00 AM CT / 10:00 AM ET Dial-in (for callers in the U.S. and
Canada): (888) 550-5424 International dial-in: (646) 960-0819
Conference ID: 3813676
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, 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 the pandemic or
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; and other
risks inherent in Coterra's businesses. In addition, the
declaration and payment of any future dividends, whether regular
base quarterly dividends, variable dividends or special dividends,
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,
2023
2022
2023
2022
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)
2,304.9
2,143.2
2,262.7
2,204.3
Daily equivalent production (MBoepd)
384.2
357.2
377.1
367.4
Permian Basin
Natural gas (Mmcf/day)
482.0
442.3
440.8
424.4
Oil (MBbl/day)
97.3
83.0
89.5
81.2
NGL (MBbl/day)
76.9
57.6
70.5
59.5
Daily equivalent production (MBoepd)
254.5
214.3
233.4
211.4
Anadarko Basin
Natural gas (Mmcf/day)
179.4
193.6
178.9
176.2
Oil (MBbl/day)
6.7
7.5
6.5
6.2
NGL (MBbl/day)
20.7
20.5
19.7
19.0
Daily equivalent production (MBoepd)
57.3
60.2
56.0
54.6
Total Company
Natural gas (Mmcf/day)
2,970.0
2,780.4
2,884.2
2,806.5
Oil (MBbl/day)
104.7
90.7
96.2
87.5
NGL (MBbl/day)
97.8
78.1
90.2
78.6
Daily equivalent production (MBoepd)
697.4
632.2
667.1
633.8
AVERAGE SALES PRICE (excluding
hedges)
Marcellus Shale
Natural gas ($/Mcf)
$
2.17
$
5.16
$
2.33
$
5.29
Permian Basin
Natural gas ($/Mcf)
$
1.19
$
3.22
$
1.28
$
5.18
Oil ($/Bbl)
$
77.26
$
82.27
$
75.98
$
94.55
NGL ($/Bbl)
$
17.65
$
23.40
$
18.44
$
32.59
Anadarko Basin
Natural gas ($/Mcf)
$
2.30
$
5.44
$
2.37
$
6.29
Oil ($/Bbl)
$
79.12
$
81.94
$
76.92
$
93.34
NGL ($/Bbl)
$
22.40
$
29.60
$
23.54
$
36.66
Total Company
Natural gas ($/Mcf)
$
2.03
$
4.87
$
2.18
$
5.34
Oil ($/Bbl)
$
77.10
$
82.26
$
75.97
$
94.47
NGL ($/Bbl)
$
18.66
$
25.02
$
19.56
$
33.58
Quarter Ended December
31,
Twelve Months Ended
December 31,
2023
2022
2023
2022
AVERAGE SALES PRICE (including
hedges)
Total Company
Natural gas ($/Mcf)
$
2.19
$
4.74
$
2.44
$
4.91
Oil ($/Bbl)
$
77.21
$
81.57
$
76.07
$
84.33
NGL ($/Bbl)
$
18.66
$
25.02
$
19.56
$
33.58
Quarter Ended December
31,
Twelve Months Ended
December 31,
2023
2022
2023
2022
WELLS DRILLED(1)
Gross wells
Marcellus Shale
20
27
73
93
Permian Basin
44
43
159
161
Anadarko Basin
2
9
32
31
66
79
264
285
Net wells
Marcellus Shale
16.2
27.0
69.2
93.0
Permian Basin
18.6
13.7
82.1
72.7
Anadarko Basin
1.8
0.1
18.1
8.9
36.6
40.8
169.4
174.6
TURN IN LINES
Gross wells
Marcellus Shale
12
26
71
81
Permian Basin
61
39
183
144
Anadarko Basin
3
11
19
26
76
76
273
251
Net wells
Marcellus Shale
12.0
26.0
71.0
78.1
Permian Basin
28.0
13.5
94.9
61.3
Anadarko Basin
—
5.9
7.1
8.7
40.0
45.4
173.0
148.1
AVERAGE RIG COUNTS
Marcellus Shale
2.6
2.9
Permian Basin
6.5
6.2
Anadarko Basin
1.3
0.9
Quarter Ended December
31,
Twelve Months Ended
December 31,
2023
2022
2023
2022
AVERAGE UNIT COSTS ($/Boe)(2)
Direct operations
$
2.51
$
2.17
$
2.31
$
1.99
Gathering, processing and
transportation
3.83
3.94
4.00
4.13
Taxes other than income
1.12
1.55
1.16
1.58
General and administrative (excluding
stock-based compensation and merger-related expense)
0.95
1.17
0.90
1.03
Unit Operating Cost
$
8.41
$
8.83
$
8.37
$
8.73
Depreciation, depletion and
amortization
7.11
7.54
6.74
7.07
Exploration
0.08
0.11
0.08
0.13
Stock-based compensation
0.23
0.28
0.24
0.37
Merger-related expense
—
—
—
0.03
Severance expense
0.03
0.18
0.05
0.27
Interest expense
0.13
0.17
0.11
0.30
$
16.00
$
17.11
$
15.60
$
16.90
_________________________________________________________
(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, 2023, the Company had the following
outstanding financial commodity derivatives:
2024
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
35,490,000
44,590,000
45,080,000
16,690,000
Weighted average floor ($/MMBtu)
$
3.00
$
2.70
$
2.75
$
2.75
Weighted average ceiling ($/MMBtu)
$
5.38
$
3.87
$
3.94
$
4.23
2025
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
9,000,000
9,100,000
9,200,000
9,200,000
Weighted average floor ($/MMBtu)
$
3.25
$
3.25
$
3.25
$
3.25
Weighted average ceiling ($/MMBtu)
$
4.79
$
4.79
$
4.79
$
4.79
2024
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
2,730
2,730
1,840
1,840
Weighted average floor ($/Bbl)
$
68.00
$
68.00
$
65.00
$
65.00
Weighted average ceiling ($/Bbl)
$
91.37
$
91.37
$
90.01
$
90.01
WTI Midland oil basis swaps
Volume (MBbl)
2,730
2,730
1,840
1,840
Weighted average differential ($/Bbl)
$
1.16
$
1.16
$
1.17
$
1.17
In January 2024, the Company entered into the following
financial commodity derivatives:
2024
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
300
455
920
920
Weighted average floor ($/Bbl)
$
65.00
$
65.00
$
65.00
$
65.00
Weighted average ceiling ($/Bbl)
$
85.02
$
85.02
$
81.49
$
81.49
WTI Midland oil basis swaps
Volume (MBbl)
300
455
920
920
Weighted average differential ($/Bbl)
$
1.10
$
1.10
$
1.10
$
1.10
Year-End Proved Reserves
The tables below provide a summary of changes in proved reserves
for the year ended December 31, 2023.
Oil (MBbl)
Natural Gas
(Bcf)
NGL (MBbl)
Total (MBOE)
PROVED RESERVES
December 31, 2022
239,755
11,173
296,765
2,398,666
Revision of previous estimates
1,084
(414
)
8,067
(59,970
)
Extensions and discoveries
44,386
823
46,148
227,660
Production
(35,110
)
(1,053
)
(32,932
)
(243,497
)
Sales of reserves
(902
)
(4
)
(592
)
(2,102
)
December 31, 2023
249,213
10,525
317,456
2,320,757
PROVED DEVELOPED RESERVES
December 31, 2022
168,649
8,543
224,706
1,817,140
December 31, 2023
173,392
8,590
234,306
1,839,219
CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In millions,
except per share amounts)
2023
2022
2023
2022
OPERATING REVENUES
Natural gas
$
553
$
1,246
$
2,292
$
5,469
Oil
742
686
2,667
3,016
NGL
168
180
644
964
Gain (loss) on derivative instruments
101
150
230
(463
)
Other
32
18
81
65
1,596
2,280
5,914
9,051
OPERATING EXPENSES
Direct operations
161
126
562
460
Gathering, processing and
transportation
246
229
975
955
Taxes other than income
72
90
283
366
Exploration
6
6
20
29
Depreciation, depletion and
amortization
456
439
1,641
1,635
General and administrative (excluding
stock-based compensation, severance expense and merger-related
costs)
61
68
220
241
Stock-based compensation(1)
15
16
59
86
Merger-related expense
—
—
—
7
Severance expense
2
11
12
62
1,019
985
3,772
3,841
Gain (loss) on sale of assets
—
—
12
(1
)
INCOME FROM OPERATIONS
577
1,295
2,154
5,209
Interest expense
23
17
73
80
Interest income
(15
)
(6
)
(47
)
(10
)
Gain on debt extinguishment
—
(2
)
—
(28
)
Other income
—
(2
)
—
(2
)
Income before income taxes
569
1,288
2,128
5,169
Income tax expense
153
256
503
1,104
NET INCOME
$
416
$
1,032
$
1,625
$
4,065
Earnings per share - Basic
$
0.55
$
1.32
$
2.14
$
5.09
Weighted-average common shares
outstanding
751
781
756
796
___________________________________________________________
(1)
Includes the impact of our performance
share awards and restricted stock.
CONDENSED CONSOLIDATED BALANCE
SHEET (Unaudited)
(In
millions)
December 31,
2023
December 31,
2022
ASSETS
Current assets
$
2,015
$
2,211
Properties and equipment, net (successful
efforts method)
17,933
17,479
Other assets
467
464
$
20,415
$
20,154
LIABILITIES, REDEEMABLE PREFERRED STOCK
AND STOCKHOLDERS' EQUITY
Current liabilities
$
1,085
$
1,193
Current portion of long-term debt
575
—
Long-term debt, net (excluding current
maturities)
1,586
2,181
Deferred income taxes
3,413
3,339
Other long term liabilities
709
771
Cimarex redeemable preferred stock
8
11
Stockholders’ equity
13,039
12,659
$
20,415
$
20,154
CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended December
31,
Twelve Months Ended
December 31,
(In
millions)
2023
2022
2023
2022
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income
$
416
$
1,032
$
1,625
$
4,065
Depreciation, depletion and
amortization
456
439
1,641
1,635
Deferred income tax expense
55
107
74
235
(Gain) loss on sale of assets
—
—
(12
)
1
(Gain) loss on derivative instruments
(101
)
(150
)
(230
)
463
Net cash received (paid) in settlement of
derivative instruments
46
(39
)
284
(762
)
Stock-based compensation and other
14
11
57
73
Income charges not requiring cash
(5
)
(7
)
(18
)
(68
)
Changes in assets and liabilities
(121
)
91
237
(186
)
Net cash provided by operating
activities
760
1,484
3,658
5,456
CASH FLOWS FROM INVESTING
ACTIVITIES
Capital expenditures for drilling,
completion and other fixed asset additions
(468
)
(501
)
(2,089
)
(1,700
)
Capital expenditures for leasehold and
property acquisitions
(2
)
(4
)
(10
)
(10
)
Proceeds from sale of assets
—
14
40
36
Net cash used in investing activities
(470
)
(491
)
(2,059
)
(1,674
)
CASH FLOWS FROM FINANCING
ACTIVITIES
Net borrowings (repayments) of debt
—
(44
)
—
(874
)
Repayments of finance leases
(2
)
(2
)
(6
)
(6
)
Common stock repurchases
(20
)
(510
)
(405
)
(1,250
)
Dividends paid
(151
)
(533
)
(890
)
(1,992
)
Cash paid for conversion of redeemable
preferred stock
—
—
(1
)
(10
)
Tax withholding on vesting of stock
awards
(9
)
(10
)
(10
)
(25
)
Capitalized debt issuance costs
—
—
(7
)
—
Cash received for stock option
exercises
1
1
2
12
Net cash used in financing activities
(181
)
(1,098
)
(1,317
)
(4,145
)
Net increase (decrease) in cash, cash
equivalents and restricted cash
$
109
$
(105
)
$
282
$
(363
)
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. 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, such as 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)
2023
2022
2023
2022
As reported - net income
$
416
$
1,032
$
1,625
$
4,065
Reversal of selected items:
(Gain) loss on sale of assets
—
—
(12
)
1
(Gain) loss on derivative
instruments(1)
(55
)
(189
)
54
(299
)
Gain on debt extinguishment
—
(2
)
—
(28
)
Stock-based compensation expense
15
16
59
86
Severance expense
2
11
12
62
Merger-related expense
—
—
—
7
Tax effect on selected items
9
37
(26
)
38
Adjusted net income
$
387
$
905
$
1,712
$
3,932
As reported - earnings per share
$
0.55
$
1.32
$
2.14
$
5.09
Per share impact of selected items
(0.03
)
(0.16
)
0.12
(0.15
)
Adjusted earnings per share
$
0.52
$
1.16
$
2.26
$
4.94
Weighted-average common shares
outstanding
751
781
756
796
______________________________________________________________
(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)
2023
2022
2023
2022
Cash flow from operating activities
$
760
$
1,484
$
3,658
$
5,456
Changes in assets and liabilities
121
(91
)
(237
)
186
Discretionary cash flow
881
1,393
3,421
5,642
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions
(468
)
(501
)
(2,089
)
(1,700
)
Free cash flow
$
413
$
892
$
1,332
$
3,942
Capital Expenditures
Quarter Ended December
31,
Twelve Months Ended December
31,
(In
millions)
2023
2022
2023
2022
Capital expenditures for drilling,
completion and other fixed asset additions
$
468
$
501
$
2,089
$
1,700
Change in accrued capital costs
(11
)
(22
)
15
27
Capital expenditures
$
457
$
479
$
2,104
$
1,727
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)
2023
2022
2023
2022
Net income
$
416
$
1,032
$
1,625
$
4,065
Plus (less):
Interest expense
23
17
73
80
Interest income
(15
)
(6
)
(47
)
(10
)
Gain on debt extinguishment
—
(2
)
—
(28
)
Other income
—
(2
)
—
(2
)
Income tax expense
153
256
503
1,104
Depreciation, depletion and
amortization
456
439
1,641
1,635
Exploration
6
6
20
29
(Gain) loss on sale of assets
—
—
(12
)
1
Non-cash (gain) loss on derivative
instruments
(55
)
(189
)
54
(299
)
Stock-based compensation
15
16
59
86
Merger-related expense
—
—
—
7
Severance expense
2
11
12
62
Adjusted EBITDAX
$
1,001
$
1,578
$
3,928
$
6,730
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,
2023
December 31,
2022
Current portion of long-term debt
$
575
$
—
Long-term debt, net
1,586
2,181
Total debt
$
2,161
$
2,181
Stockholders’ equity
13,039
12,659
Total capitalization
$
15,200
$
14,840
Total debt
$
2,161
$
2,181
Less: Cash and cash equivalents
(956
)
(673
)
Net debt
$
1,205
$
1,508
Net debt
$
1,205
$
1,508
Stockholders’ equity
13,039
12,659
Total adjusted capitalization
$
14,244
$
14,167
Total debt to total capitalization
ratio
14.2
%
14.7
%
Less: Impact of cash and cash
equivalents
5.7
%
4.1
%
Net debt to adjusted capitalization
ratio
8.5
%
10.6
%
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,
2023
December 31,
2022
Total debt
$
2,161
$
2,181
Net income
1,625
$
4,065
Total debt to net income ratio
1.3 x
0.5 x
Net debt (as defined above)
$
1,205
$
1,508
Adjusted EBITDAX (Twelve months ended
December 31)
3,928
6,730
Net debt to Adjusted EBITDAX
0.3 x
0.2 x
2024 Guidance
The tables below present full-year and first quarter 2024
guidance.
Full Year Guidance
2023 Guidance
2023 Actual
2024 Guidance
Low Mid High
Total Equivalent Production (MBoed)
655 - 665
667
635 - 655 - 675
Gas (Mmcf/day)
2,840 - 2,870
2,884
2,650 - 2,725 - 2,800
Oil (MBbl/day)
94.5 - 95.5
96.2
99.0 - 102.0 - 105.0
Net wells turned in line
Marcellus Shale
65 - 75
71
37 - 40 - 43
Permian Basin
85 - 95
95
75 - 83 - 90
Anadarko Basin
7-7
7
20 - 23 - 25
Incurred capital expenditures ($ in
millions)
Total Company
$2,000 - $2,200
$2,104
$1,750 - $1,850 - $1,950
Drilling and completion
Marcellus Shale
$790 - $880
$834
$350- $375 - $400
Permian Basin
$880 - $980
$932
$945 - $1,000 - $1,055
Anadarko Basin
$160 - $170
$151
$270 - $290 - $310
Midstream, saltwater disposal and
infrastructure
$170 - $170
$187
$185 - $185 - $185
First Quarter Guidance
Fourth Quarter 2023
Guidance
Fourth Quarter 2023
Actual
First Quarter 2024
Guidance
Low Mid High
Total Equivalent Production (MBoed)
645 - 680
697
660 - 675 - 690
Gas (Mmcf/day)
2,780 - 2,900
2,970
2,850 - 2,900 - 2,950
Oil (MBbl/day)
98.0 - 102.0
104.7
95.0 - 97.0 - 99.0
Net wells turned in line
Marcellus Shale
8 - 14
12
20 - 23 - 26
Permian Basin
20 - 30
28
15 - 21 - 27
Anadarko Basin
0 - 0
0
0 - 0 - 0
Incurred capital expenditures ($ in
millions)
Total Company
$460 - $530
$457
$460 - $500 - $540
Drilling and completion
Marcellus Shale
$175
Permian Basin
$237
Anadarko Basin
$15
Midstream, saltwater disposal and
infrastructure
$31
View source
version on businesswire.com: https://www.businesswire.com/news/home/20240222478637/en/
Investor Contact Daniel Guffey - Vice President of
Finance, Planning and Investor Relations 281.589.4875
Hannah Stuckey - Investor Relations Manager
281.589.4983
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