Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the
“Company”) today reported third-quarter 2024 financial and
operating results and declared a quarterly dividend of $0.21 per
share. Additionally, the Company provided fourth-quarter production
and capital guidance and updated full-year 2024 guidance.
Tom Jorden, Chairman, CEO and President of Coterra, noted,
"Coterra continues to exceed its 2024 plan and has strong momentum
with significant optionality heading into 2025. Our teams continue
to deliver strong and improving capital efficiency through
operational execution, all of which is guided by our relentless
focus on economic returns. The Company's strong positioning is
underpinned by its advantaged balance sheet, operational aptitude,
diversified commodity mix and its durable, high-quality
inventory.
We are also pleased to announce our three new LNG agreements.
The U.S. has an abundant, low-cost natural gas resource that can
help support energy reliability and energy affordability around the
world. America's role as a major energy exporter strengthens our
nation's standing on the global stage. As part of Coterra’s ongoing
strategy, these agreements further diversify our natural gas
marketing portfolio with the addition of international LNG pricing
exposure to European and Asian markets."
Key Takeaways & Updates
- For the third quarter of 2024, total barrels of oil equivalent
(BOE) production, natural gas production, and oil production all
beat the high-end of guidance, and capital expenditures (non-GAAP)
came in below the low-end of guidance.
- Increasing full-year 2024 production guidance mid-point for
BOE, natural gas, and oil. The full-year 2024 oil guidance
mid-point now assumes 12% year over year growth and a 5% increase
compared to the initial guidance mid-point provided in February.
These upward revisions throughout the year have been driven by
faster cycle times and strong well performance across our
portfolio.
- Lowering full-year 2024 capital expenditure (non-GAAP) guidance
by $50 million at the mid-point, to $1.75-1.85 billion, driven by
lower midstream, saltwater disposal, and infrastructure capital as
well as lower Marcellus activity.
- During the quarter, the Company signed three new LNG agreements
to sell a total of 200 MMcfpd (million cubic feet per day) of
natural gas, indexed to international price points. Sales will
begin in 2027 and 2028 and will be sourced from the Permian Basin,
Anadarko Basin, and Marcellus Shale.
- For the third quarter of 2024, shareholder returns totaled 96%
of Free Cash Flow (non-GAAP), inclusive of our declared quarterly
base dividend and $111 million of share repurchases during the
quarter (cash basis, excluding 1% excise tax). The Company remains
committed to returning 50% or greater of its annual Free Cash Flow
(non-GAAP) to shareholders and has returned 100% year to date, in
addition to the retirement of $75 million of debt, net of new issue
proceeds.
- To date, 36 of the 57 Windham Row wells have come online.
- Currently, 10 additional wells are expected to come online by
the end of the year.
- The final 11 wells are expected to come online in first-quarter
2025.
Third-Quarter 2024 Highlights
- Net Income (GAAP) totaled $252 million, or $0.34 per share.
Adjusted Net Income (non-GAAP) was $233 million, or $0.32 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $755
million. Discretionary Cash Flow (non-GAAP) totaled $670 million.
Free Cash Flow (non-GAAP) totaled $277 million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $393 million. Capital
expenditures from drilling, completion and other fixed asset
additions (non-GAAP) totaled $418 million, below the low-end of our
guidance range of $450 to $530 million.
- Unit operating cost (reflecting costs from direct operations,
transportation, production taxes and G&A) totaled $8.73 per
BOE, within our annual guidance range of $7.45 to $9.55 per
BOE.
- Total equivalent production of 669 MBoepd (thousand barrels of
oil equivalent per day), was 3% above the high-end of guidance (620
to 650 MBoepd), driven by timing and strong well performance in all
three of our regions.
- Oil production averaged 112.3 MBopd (thousand barrels of oil
per day), slightly exceeding the high-end of guidance (107 to 111
MBopd) by 1%.
- Natural gas production averaged 2,682 MMcfpd, exceeding the
high end of guidance (2,500 to 2,630 MMcfpd) by 2%, driven
primarily by Permian growth.
- NGLs production averaged 109.7 MBopd.
- Realized average prices:
- Oil was $74.04 per Bbl (barrel), excluding the effect of
commodity derivatives, and $74.18 per Bbl, including the effect of
commodity derivatives.
- Natural Gas was $1.30 per Mcf (thousand cubic feet), excluding
the effect of commodity derivatives, and $1.41 per Mcf, including
the effect of commodity derivatives.
- NGLs were $18.42 per Bbl.
Shareholder Return Highlights
- Common Dividend: On October 31, 2024, Coterra's Board of
Directors (the "Board") approved a quarterly base dividend of $0.21
per share, equating to a 3.5% annualized yield, based on the
Company's $24.13 closing share price on October 30, 2024. The
dividend will be paid on November 27, 2024 to holders of record on
November 14, 2024.
- Share Repurchases: During the quarter, the Company
repurchased 4.3 million shares for $111 million at a
weighted-average price of approximately $25.15 per share, leaving
$1.2 billion remaining as of September 30, 2024 on its $2.0 billion
share repurchase authorization. Year-to-date, the Company
repurchased 15 million shares for $401 million.
- Shareholder Return: During the quarter, shareholder
returns amounted to $265 million, comprised of $154 million of
declared dividends and $111 million of share repurchases.
- Reiterate Shareholder Return Strategy: Coterra is
committed to returning 50% or greater of annual Free Cash Flow
(non-GAAP) to shareholders through its $0.84 per share annual
dividend and share repurchases. Year to date, Coterra has returned
100% of Free Cash Flow (non-GAAP) to shareholders.
Guidance Updates
- Lowered 2024 capital expenditures (non-GAAP) to $1.75 to $1.85
billion, down from $1.75 to $1.95 billion.
- Increased 2024 oil production guidance to 107 to 108 MBopd, up
0.5 MBopd at the mid-point versus prior guidance.
- Increased 2024 natural gas production guidance to 2,735 to
2,775 MMcfpd, up 1% at the mid-point versus prior guidance.
- Increased 2024 BOE production guidance to 660 to 675 MBoepd, up
1% at the mid-point versus prior guidance.
- Announced fourth-quarter 2024 total equivalent production of
630 to 660 MBoepd, oil production of 106 to 110 MBopd, natural gas
production of 2,530 to 2,660 MMcfpd, and capital expenditures
(non-GAAP) of $410 to $500 million.
- Estimate 2024 Discretionary Cash Flow (non-GAAP) of
approximately $2.9 billion and 2024 Free Cash Flow (non-GAAP) of
approximately $1.1 billion, at $75.58/bbl WTI and $2.22/mmbtu
(metric million British thermal unit) annual average NYMEX
assumptions.
- For more details on annual and fourth quarter 2024 guidance,
see 2024 Guidance Section in the tables below.
Strong Financial Position
As of September 30, 2024, Coterra had total debt outstanding of
$2.066 billion. During the quarter, Coterra repaid $575 million of
its 3.65% weighted-average private placement senior notes that
matured in September 2024. During the quarter, the Company expanded
its credit facility to $2.0 billion, up from $1.5 billion. The
Company exited the quarter with cash and cash equivalents of $843
million, and no debt outstanding under its $2.0 billion revolving
credit facility, resulting in total liquidity of approximately
$2.843 billion. Coterra's net debt to trailing twelve-month EBITDAX
ratio (non-GAAP) at September 30, 2024 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.
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.
Coterra published its 2024 Sustainability report on August 1,
2024.
Third-Quarter 2024 Conference Call
Coterra will host a conference call tomorrow, Friday, November
1, 2024, at 8:00 AM CT (9:00 AM ET), to discuss third-quarter 2024
financial and operating results.
Conference Call Information
Date:
November 1, 2024
Time:
8:00 AM CT / 9:00 AM ET
Dial-in (for callers in the U.S. and
Canada):
(800) 715-9871
International dial-in:
+1 (646) 307-1963
Conference ID:
7309925
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 operations focused 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, 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; 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, (geopolitical
disruptions such as the war in Ukraine or conflict in the Middle
East or further escalation thereof); 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; the impact of public health crises, including pandemics
and epidemics and any related company or governmental policies or
actions, financial condition and results of operations; 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 September
30,
Nine Months Ended
September 30,
2024
2023
2024
2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)
1,928.5
2,286.4
2,117.2
2,248.5
Daily equivalent production (MBoepd)
321.4
381.1
352.9
374.7
Permian Basin
Natural gas (Mmcf/day)
531.2
446.4
500.9
426.9
Oil (MBbl/day)
102.7
86.6
99.8
86.9
NGL (MBbl/day)
82.7
75.4
77.0
68.3
Daily equivalent production (MBoepd)
273.9
236.3
260.2
226.3
Anadarko Basin
Natural gas (Mmcf/day)
218.8
168.3
186.6
178.8
Oil (MBbl/day)
9.5
5.2
7.5
6.4
NGL (MBbl/day)
26.9
19.1
22.6
19.3
Daily equivalent production (MBoepd)
72.9
52.3
61.1
55.5
Total Company
Natural gas (Mmcf/day)
2,682.0
2,903.2
2,806.8
2,855.3
Oil (MBbl/day)
112.3
91.9
107.4
93.3
NGL (MBbl/day)
109.7
94.5
99.6
87.7
Daily equivalent production (MBoepd)
669.1
670.3
674.8
656.9
AVERAGE SALES PRICE (excluding
hedges)
Marcellus Shale
Natural gas ($/Mcf)
$
1.78
$
1.80
$
1.89
$
2.39
Permian Basin
Natural gas ($/Mcf)
$
(0.63
)
$
1.58
$
(0.06
)
$
1.31
Oil ($/Bbl)
$
73.96
$
80.84
$
76.14
$
75.50
NGL ($/Bbl)
$
17.30
$
18.56
$
18.83
$
18.75
Anadarko Basin
Natural gas ($/Mcf)
$
1.66
$
2.37
$
1.68
$
2.39
Oil ($/Bbl)
$
74.83
$
80.35
$
76.34
$
76.15
NGL ($/Bbl)
$
21.90
$
23.30
$
22.20
$
23.95
Total Company
Natural gas ($/Mcf)
$
1.30
$
1.80
$
1.53
$
2.23
Oil ($/Bbl)
$
74.04
$
80.80
$
76.16
$
75.54
NGL ($/Bbl)
$
18.42
$
19.52
$
19.59
$
19.90
Quarter Ended September
30,
Nine Months Ended September
30,
2024
2023
2024
2023
AVERAGE SALES PRICE (including
hedges)
Total Company
Natural gas ($/Mcf)
$
1.41
$
2.01
$
1.65
$
2.53
Oil ($/Bbl)
$
74.18
$
80.74
$
76.17
$
75.64
NGL ($/Bbl)
$
18.42
$
19.52
$
19.59
$
19.90
Quarter Ended September
30,
Nine Months Ended
September 30,
2024
2023
2024
2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale
4
17
26
53
Permian Basin
63
43
174
115
Anadarko Basin
20
13
39
30
87
73
239
198
Net wells
Marcellus Shale
4.0
17.0
25.0
53.0
Permian Basin
25.9
25.6
75.9
63.5
Anadarko Basin
6.3
7.9
20.0
16.3
36.2
50.5
120.9
132.8
TURN IN LINES
Gross wells
Marcellus Shale
7
14
30
59
Permian Basin
61
43
159
122
Anadarko Basin
10
9
41
16
78
66
230
197
Net wells
Marcellus Shale
7.0
14.0
30.0
59.0
Permian Basin
23.9
24.7
68.4
66.9
Anadarko Basin
4.6
7.0
19.9
7.1
35.5
45.7
118.3
133.0
AVERAGE RIG COUNTS
Marcellus Shale
0.6
2.3
1.3
2.8
Permian Basin
8.0
7.0
8.0
6.3
Anadarko Basin
1.0
1.0
1.4
1.3
_______________________________________________________________________________
(1) Wells drilled represents wells drilled
to total depth during the period.
Quarter Ended September
30,
Nine Months Ended
September 30,
2024
2023
2024
2023
AVERAGE UNIT COSTS ($/Boe) (1)
Direct operations
$
2.69
$
2.22
$
2.60
$
2.24
Gathering, processing and
transportation
3.97
3.81
3.98
4.07
Taxes other than income
1.08
1.00
1.05
1.18
General and administrative (excluding
stock-based compensation and severance expense)
0.99
0.96
0.91
0.89
Unit Operating Cost
$
8.73
$
7.99
$
8.54
$
8.38
Depreciation, depletion and
amortization
7.73
6.82
7.32
6.61
Exploration
0.15
0.08
0.10
0.08
Stock-based compensation
0.23
0.35
0.23
0.25
Severance expense
—
(0.02
)
0.03
0.06
Interest expense, net
0.12
0.12
0.14
0.10
$
16.96
$
15.32
$
16.36
$
15.46
_______________________________________________________________________________
(1) Total unit costs may differ from the
sum of the individual costs due to rounding.
Derivatives
Information
As of September 30, 2024, the Company had
the following outstanding financial commodity derivatives:
2024
Oil
Fourth Quarter
WTI oil collars
Volume (MBbl)
3,680
Weighted average floor ($/Bbl)
$
65.00
Weighted average ceiling ($/Bbl)
$
86.20
WTI Midland oil basis swaps
Volume (MBbl)
4,600
Weighted average differential ($/Bbl)
$
1.13
2025
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
3,330
3,367
2,024
2,024
Weighted average floor ($/Bbl)
$
61.89
$
61.89
$
62.05
$
62.05
Weighted average ceiling ($/Bbl)
$
81.40
$
81.40
$
81.15
$
81.15
WTI Midland oil basis swaps
Volume (MBbl)
3,150
3,185
1,840
1,840
Weighted average differential ($/Bbl)
$
1.18
$
1.18
$
1.11
$
1.11
2024
Natural Gas
Fourth Quarter
NYMEX collars
Volume (MMBtu)
34,990,000
Weighted average floor ($/MMBtu)
$
2.75
Weighted average ceiling ($/MMBtu)
$
4.46
2025
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
36,000,000
36,400,000
36,800,000
36,800,000
Weighted average floor ($/MMBtu)
$
2.88
$
2.88
$
2.88
$
2.88
Weighted average ceiling ($/MMBtu)
$
4.70
$
4.15
$
4.15
$
6.00
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 October 2024, the Company entered into
the following financial commodity derivatives:
2024
2025
Oil
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
305
810
819
1,288
1,288
Weighted average floor ($/Bbl)
$
60.00
$
57.78
$
57.78
$
58.57
$
58.57
Weighted average ceiling ($/Bbl)
$
92.57
$
80.18
$
80.18
$
80.09
$
80.09
WTI Midland oil basis swaps
Volume (MBbl)
—
540
546
1,012
1,012
Weighted average differential ($/Bbl)
$
—
$
1.00
$
1.00
$
1.02
$
1.02
CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended September
30,
Nine Months Ended
September 30,
(In millions,
except per share amounts)
2024
2023
2024
2023
OPERATING REVENUES
Oil
$
765
$
684
$
2,240
$
1,925
Natural gas
320
481
1,177
1,739
NGL
186
170
535
476
Gain (loss) on derivative instruments
64
3
48
129
Other
24
18
63
49
1,359
1,356
4,063
4,318
OPERATING EXPENSES
Direct operations
165
137
481
401
Gathering, processing and
transportation
245
235
737
729
Taxes other than income
66
62
194
211
Exploration
9
5
19
14
Depreciation, depletion and
amortization
475
421
1,354
1,185
General and administrative (excluding
stock-based compensation and severance expense)
61
59
175
159
Stock-based compensation
14
21
43
44
Severance expense
—
(1
)
—
10
1,035
939
3,003
2,753
Gain on sale of assets
3
7
3
12
INCOME FROM OPERATIONS
327
424
1,063
1,577
Interest expense
24
17
77
50
Interest income
(16
)
(10
)
(51
)
(32
)
Income before income taxes
319
417
1,037
1,559
Income tax provision (benefit)
Current
104
102
273
331
Deferred
(37
)
(8
)
(60
)
19
Total income tax provision
67
94
213
350
NET INCOME
$
252
$
323
$
824
$
1,209
Earnings per share - Basic
$
0.34
$
0.43
$
1.11
$
1.59
Weighted-average common shares
outstanding
738
753
743
757
CONDENSED CONSOLIDATED BALANCE
SHEET (Unaudited)
(In
millions)
September 30,
2024
December 31,
2023
ASSETS
Cash and cash equivalents
$
843
$
956
Other current assets
892
1,059
Properties and equipment, net (successful
efforts method)
17,941
17,933
Other assets
450
467
$
20,126
$
20,415
LIABILITIES, REDEEMABLE PREFERRED STOCK
AND STOCKHOLDERS' EQUITY
Current liabilities
$
1,080
$
1,085
Current portion of long-term debt
—
575
Long-term debt, net (excluding current
maturities)
2,066
1,586
Deferred income taxes
3,359
3,413
Other long term liabilities
579
709
Cimarex redeemable preferred stock
8
8
Stockholders’ equity
13,034
13,039
$
20,126
$
20,415
CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended September
30,
Nine Months Ended
September 30,
(In millions)
2024
2023
2024
2023
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income
$
252
$
323
$
824
$
1,209
Depreciation, depletion and
amortization
475
421
1,354
1,185
Deferred income tax (benefit) expense
(37
)
(8
)
(60
)
19
(Gain) / loss on sale of assets
(3
)
(7
)
(3
)
(12
)
Exploratory dry hole cost
5
—
5
—
(Gain) / loss on derivative
instruments
(64
)
(3
)
(48
)
(129
)
Net cash received in settlement of
derivative instruments
28
55
90
238
Stock-based compensation and other
18
18
43
43
Income charges not requiring cash
(4
)
(3
)
(13
)
(13
)
Changes in assets and liabilities
85
(38
)
(23
)
358
Net cash provided by operating
activities
755
758
2,169
2,898
CASH FLOWS FROM INVESTING
ACTIVITIES
Capital expenditures for drilling,
completion and other fixed asset additions
(393
)
(546
)
(1,329
)
(1,621
)
Capital expenditures for leasehold and
property acquisitions
(3
)
(2
)
(6
)
(8
)
Purchases of short-term investments
—
—
(250
)
—
Proceeds from sale of short-term
investments
250
—
250
—
Proceeds from sale of assets
7
7
8
40
Net cash used in investing activities
(139
)
(541
)
(1,327
)
(1,589
)
CASH FLOWS FROM FINANCING
ACTIVITIES
Proceeds from issuance of debt
—
—
499
—
Repayments of debt
(575
)
—
(575
)
—
Common stock repurchases
(111
)
(60
)
(401
)
(385
)
Dividends paid
(156
)
(151
)
(470
)
(739
)
Other
(5
)
—
(12
)
(12
)
Net cash used in financing activities
(847
)
(211
)
(959
)
(1,136
)
Net increase (decrease) in cash, cash
equivalents and restricted cash
$
(231
)
$
6
$
(117
)
$
173
Reconciliation of Capital
Expenditures
Capital expenditures is defined as cash
paid for capital expenditures for drilling, completion and other
fixed asset additions less changes in accrued capital costs.
Quarter Ended September
30,
Nine Months Ended
September 30,
(In millions)
2024
2023
2024
2023
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions (GAAP)
$
393
$
546
$
1,329
$
1,621
Change in accrued capital costs
20
(4
)
11
26
Exploratory dry-hole cost
5
—
5
—
Capital expenditures for drilling,
completion and other fixed asset additions (non-GAAP)
$
418
$
542
$
1,345
$
1,647
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, 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 September
30,
Nine Months Ended
September 30,
(In millions,
except per share amounts)
2024
2023
2024
2023
As reported - net income
$
252
$
323
$
824
$
1,209
Reversal of selected items:
Gain on sale of assets
(3
)
(7
)
(3
)
(12
)
(Gain) loss on derivative
instruments(1)
(36
)
52
42
109
Stock-based compensation expense
14
21
43
44
Severance expense
—
(1
)
—
10
Tax effect on selected items
6
(15
)
(19
)
(34
)
Adjusted net income
$
233
$
373
$
887
$
1,326
As reported - earnings per share
$
0.34
$
0.43
$
1.11
$
1.59
Per share impact of selected items
(0.02
)
0.07
0.08
0.16
Adjusted earnings per share
$
0.32
$
0.50
$
1.19
$
1.75
Weighted-average common shares
outstanding
738
753
743
757
_______________________________________________________________________________
(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 September
30,
Nine Months Ended
September 30,
(In
millions)
2024
2023
2024
2023
Cash flow from operating activities
$
755
$
758
$
2,169
$
2,898
Changes in assets and liabilities
(85
)
38
23
(358
)
Discretionary cash flow
670
796
2,192
2,540
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions
(393
)
(546
)
(1,329
)
(1,621
)
Free Cash Flow
$
277
$
250
$
863
$
919
Reconciliation of Adjusted EBITDAX
Adjusted EBITDAX is defined as net income plus interest expense,
interest income, 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, and severance
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 September
30,
Nine Months Ended
September 30,
(In millions)
2024
2023
2024
2023
Net income
$
252
$
323
$
824
$
1,209
Plus (less):
Interest expense
24
17
77
50
Interest income
(16
)
(10
)
(51
)
(32
)
Income tax expense
67
94
213
350
Depreciation, depletion and
amortization
475
421
1,354
1,185
Exploration
9
5
19
14
Gain on sale of assets
(3
)
(7
)
(3
)
(12
)
Non-cash loss on derivative
instruments
(36
)
52
42
109
Severance expense
—
(1
)
—
10
Stock-based compensation
14
21
43
44
Adjusted EBITDAX
$
786
$
915
$
2,518
$
2,927
Trailing Twelve Months
Ended
(In
millions)
September 30,
2024
December 31,
2023
Net income
$
1,240
$
1,625
Plus (less):
Interest expense
100
73
Interest income
(66
)
(47
)
Income tax expense
366
503
Depreciation, depletion and
amortization
1,810
1,641
Exploration
25
20
Gain on sale of assets
(3
)
(12
)
Non-cash loss on derivative
instruments
(13
)
54
Severance expense
2
12
Stock-based compensation
58
59
Adjusted EBITDAX (trailing twelve
months)
$
3,519
$
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 and short-term investments 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 and
short-term investments 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 and short-term investments to reduce debt in
calculating the Net Debt to Adjusted Capitalization ratio.
(In
millions)
September 30,
2024
December 31,
2023
Current portion of long-term debt
$
—
$
575
Long-term debt, net
2,066
1,586
Total debt
2,066
2,161
Stockholders’ equity
13,034
13,039
Total capitalization
$
15,100
$
15,200
Total debt
$
2,066
$
2,161
Less: Cash and cash equivalents
(843
)
(956
)
Net debt
$
1,223
$
1,205
Net debt
$
1,223
$
1,205
Stockholders’ equity
13,034
13,039
Total adjusted capitalization
$
14,257
$
14,244
Total debt to total capitalization
ratio
13.7
%
14.2
%
Less: Impact of cash and cash
equivalents
5.1
%
5.7
%
Net debt to adjusted capitalization
ratio
8.6
%
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)
September 30,
2024
December 31,
2023
Total debt
$
2,066
$
2,161
Net income
1,240
1,625
Total debt to net income ratio
1.7 x
1.3 x
Net debt (as defined above)
$
1,223
$
1,205
Adjusted EBITDAX (Trailing twelve
months)
3,519
3,928
Net debt to Adjusted EBITDAX
0.3 x
0.3 x
2024 Guidance
The tables below present full-year and
third quarter 2024 guidance.
Full Year Guidance
2024 Guidance (August)
Updated 2024 Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
645
—
660
—
675
660
—
668
—
675
Gas (Mmcf/day)
2,675
—
2,725
—
2,775
2,735
—
2,755
—
2,775
Oil (MBbl/day)
105.5
—
107
—
108.5
107
—
107.5
—
108
Net wells turned in line
Marcellus Shale
37
—
40
—
43
40
Permian Basin
80
—
85
—
90
No change
Anadarko Basin
21
—
24
—
27
No change
Capital expenditures ($ in millions)
Total Company
$1,750
—
$1,850
—
$1,950
$1,750
—
$1,800
—
$1,850
Drilling and completion
Marcellus Shale
$375 midpoint
$300 midpoint
Permian Basin
$1,000 midpoint
$1,050 midpoint
Anadarko Basin
$290 midpoint
$300 midpoint
Midstream, saltwater disposal and
infrastructure
$185 midpoint
$150 midpoint
Commodity price assumptions:
WTI ($ per bbl)
$80
$76
Henry Hub ($ per mmbtu)
$2.37
$2.22
Cash Flow & Investment ($ in
billions)
Discretionary Cash Flow
$3.2
$2.9
Capital Expenditures
$1.75
—
$1.85
—
$1.95
$1.75
—
$1.80
—
$1.85
Free Cash Flow (DCF - cash capex)
$1.3
$1.1
$ per boe, unless noted:
Lease operating expense + workovers +
region office
$2.15
—
$2.50
—
$2.85
No change
Gathering, processing, &
transportation
$3.50
—
$4.00
—
$4.50
No change
Taxes other than income
$1.00
—
$1.10
—
$1.20
No change
General & administrative (1)
$0.80
—
$0.90
—
$1.00
No change
Unit Operating Cost
$7.45
—
$8.50
—
$9.55
No change
_______________________________________________________________________________
(1) Excludes stock-based compensation and
severance expense
Quarterly Guidance
Third Quarter 2024
Guidance
Third Quarter 2024
Actual
Fourth Quarter 2024
Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
620
—
635
—
650
669
630
—
645
—
660
Gas (Mmcf/day)
2,500
—
2,565
—
2,630
2,682
2,530
—
2,595
—
2,660
Oil (MBbl/day)
107.0
—
109.0
—
111.0
112.3
106.0
—
108.0
—
110.0
Net wells turned in line
Marcellus Shale
0
—
4
—
7
7
11
Permian Basin
15
—
20
—
25
24
13
—
18
—
23
Anadarko Basin
5
—
5
—
5
5
1
—
4
—
7
Capital expenditures ($ in millions)
Total Company
$450
—
$480
—
$530
$418
$410
—
$455
—
$500
View source
version on businesswire.com: https://www.businesswire.com/news/home/20241031609078/en/
Investor Contact Daniel Guffey - Vice President of
Finance, IR & Treasury 281.589.4875 Hannah Stuckey -
Investor Relations Manager 281.589.4983
Coterra Energy (NYSE:CTRA)
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