Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the
“Company”) today reported second-quarter 2024 financial and
operating results and declared a quarterly dividend of $0.21 per
share. Additionally, the Company provided third-quarter production
and capital guidance and updated full-year 2024 guidance.
Key Takeaways & Updates
- For the second quarter of 2024, total barrels of oil equivalent
(BOE) production, natural gas production, and oil production all
beat the high-end of guidance, and incurred capital expenditures
(non-GAAP) came in near the low-end of guidance.
- Increasing full-year 2024 BOE production guidance by 1% and oil
production guidance by 2.4% from guidance provided in May, driven
by faster cycle times and strong well performance. Maintaining
full-year 2024 incurred capital expenditure (non-GAAP)
guidance.
- For the second quarter of 2024, shareholder returns totaled
120% of Free Cash Flow (non-GAAP), inclusive of our declared
quarterly base dividend and $140 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 103%
year to date.
- Simul-frac efficiencies are exceeding expectations on our
Windham Row Development. To date, 21 of the planned wells in the
row have come online an average of 4 days ahead of schedule. We now
plan to add an additional 3 Harkey wells to the project, bringing
total wells in the row to 57, and further improving the capital
efficiency of the project. Furthermore, due to early success, we
now plan to simul-frac 45 of the 57 wells in the row.
Tom Jorden, Chairman, CEO and President of Coterra, noted,
"Coterra's second quarter results continue the trend of delivering
outstanding performance. The ingenuity and hard work of our
operating team are driving results that exceed expectations across
our portfolio of high-quality assets. As we move into the second
half of 2024, we remain focused on executing our plan while
maintaining significant investment optionality between oil and gas
in 2025. Coterra's investment thesis remains strong. Operational
excellence, efficient development of our diversified, low-cost,
long-life assets, our fortress balance sheet, and an unwavering
commitment to shareholder returns underpin our value
proposition."
Second-Quarter 2024 Highlights
- Net Income (GAAP) totaled $220 million, or $0.30 per share.
Adjusted Net Income (non-GAAP) was $272 million, or $0.37 per
share.
- Cash Flow From Operating Activities (GAAP) totaled $558
million. Discretionary Cash Flow (non-GAAP) totaled $725
million.
- Cash paid for capital expenditures for drilling, completion and
other fixed asset additions (GAAP) totaled $479 million. Incurred
capital expenditures from drilling, completion and other fixed
asset additions (non-GAAP) totaled $477 million, near the low end
of our guidance range of $470 to $550 million.
- Free Cash Flow (non-GAAP) totaled $246 million.
- Unit operating cost (reflecting costs from direct operations,
transportation, production taxes and G&A) totaled $8.35 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 above the high end of guidance (625 to
655 MBoepd), driven by improved cycle times and strong well
performance in all three of our regions.
- Oil production averaged 107.2 MBopd (thousand barrels of oil
per day), slightly exceeding the high end of guidance (103 to 107
MBopd).
- Natural gas production averaged 2,780 MMcfpd (million cubic
feet per day), exceeding the high end of guidance (2,600 to 2,700
MMcfpd) as Marcellus base production outperformed
expectations.
- NGLs production averaged 98.8 MBoepd.
- Realized average prices:
- Oil was $79.37 per Bbl (barrel), excluding the effect of
commodity derivatives, and $79.39 per Bbl, including the effect of
commodity derivatives.
- Natural Gas was $1.26 per Mcf (thousand cubic feet), excluding
the effect of commodity derivatives, and $1.40 per Mcf, including
the effect of commodity derivatives.
- NGLs were $19.53 per Bbl.
Shareholder Return Highlights
- Common Dividend: On August 1, 2024, Coterra's Board of
Directors (the "Board") approved a quarterly base dividend of $0.21
per share, equating to a 3.3% annualized yield, based on the
Company's $25.80 closing share price on July 31, 2024. The dividend
will be paid on August 29, 2024 to holders of record on August 15,
2024.
- Share Repurchases: During the quarter, the Company
repurchased 5.0 million shares for $140 million (cash basis,
excluding 1% excise tax) at a weighted-average price of
approximately $27.72 per share, leaving $1.3 billion remaining as
of June 30, 2024 on its $2.0 billion share repurchase
authorization.
- Total Shareholder Return: During the quarter, total
shareholder returns amounted to $295 million, comprised of $155
million of declared dividends and $140 million of share repurchases
(cash basis, excluding 1% excise tax).
- 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
103% of Free Cash Flow (non-GAAP) to shareholders.
Guidance Updates:
- Reiterated 2024 incurred capital expenditures (non-GAAP) of
$1.75 to $1.95 billion.
- Increased 2024 oil production guidance to 105.5 to 108.5 MBopd,
up 2.4% at the mid-point versus prior guidance.
- Maintained 2024 natural gas production guidance at the
mid-point, tightened range to 2,675 to 2,775 MMcfpd.
- Increased 2024 BOE production guidance to 645 to 675, up 1% at
the mid-point versus prior guidance.
- Announced third-quarter 2024 total equivalent production of 620
to 650 MBoepd, oil production of 107.0 to 111.0 MBopd, natural gas
production of 2,500 to 2,630 MMcfpd, and incurred capital
expenditures (non-GAAP) of $450 to $530 million.
- Estimate 2024 Discretionary Cash Flow (non-GAAP) of
approximately $3.2 billion and 2024 Free Cash Flow (non-GAAP) of
approximately $1.3 billion, at $80/bbl WTI and $2.37/mmbtu annual
average NYMEX assumptions.
- For more details on annual and third quarter 2024 guidance, see
2024 Guidance Section in the tables below.
Strong Financial Position
As of June 30, 2024, Coterra had total debt outstanding of
$2.646 billion, of which $575 million is due in September 2024.
Coterra expects to retire its September 2024 maturity with cash on
hand. The Company exited the quarter with cash and cash equivalents
of $1.07 billion, $250 million in short-term investments, and no
debt outstanding under its $1.5 billion revolving credit facility,
resulting in total liquidity of approximately $2.82 billion.
Coterra's net debt to trailing twelve-month EBITDAX ratio
(non-GAAP) at June 30, 2024 was 0.4x.
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.
Second-Quarter 2024 Conference Call
Coterra will host a conference call tomorrow, Friday, August 2,
2024, at 8:00 AM CT (9:00 AM ET), to discuss second-quarter 2024
financial and operating results.
Conference Call Information
Date: August 2, 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: 8017228
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, 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 and epidemics and any related company
or governmental policies or actions, 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, (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; 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 June
30,
Six Months Ended June
30,
2024
2023
2024
2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)
2,114.4
2,322.8
2,212.6
2,229.1
Daily equivalent production (MBoepd)
352.4
387.1
368.8
371.5
Permian Basin
Natural gas (Mmcf/day)
484.5
406.7
485.6
416.9
Oil (MBbl/day)
99.6
89.7
98.3
87.0
NGL (MBbl/day)
78.1
65.4
74.1
64.7
Daily equivalent production (MBoepd)
258.4
222.9
253.3
221.2
Anadarko Basin
Natural gas (Mmcf/day)
179.4
173.9
170.3
184.1
Oil (MBbl/day)
7.5
6.1
6.5
7.0
NGL (MBbl/day)
20.6
19.6
20.3
19.4
Daily equivalent production (MBoepd)
58.0
54.7
55.2
57.1
Total Company
Natural gas (Mmcf/day)
2,779.8
2,904.4
2,869.9
2,830.9
Oil (MBbl/day)
107.2
95.8
104.9
94.0
NGL (MBbl/day)
98.8
85.0
94.5
84.2
Daily equivalent production (MBoepd)
669.2
664.9
677.7
650.1
AVERAGE SALES PRICE (excluding
hedges)
Marcellus Shale
Natural gas ($/Mcf)
$
1.66
$
1.78
$
1.94
$
2.70
Permian Basin
Natural gas ($/Mcf)
$
(0.53
)
$
0.92
$
0.25
$
1.16
Oil ($/Bbl)
$
79.37
$
71.71
$
77.30
$
72.80
NGL ($/Bbl)
$
18.95
$
15.36
$
19.70
$
18.85
Anadarko Basin
Natural gas ($/Mcf)
$
1.35
$
1.57
$
1.70
$
2.40
Oil ($/Bbl)
$
79.40
$
74.32
$
77.45
$
74.56
NGL ($/Bbl)
$
21.75
$
21.02
$
22.39
$
24.27
Total Company
Natural gas ($/Mcf)
$
1.26
$
1.65
$
1.64
$
2.46
Oil ($/Bbl)
$
79.37
$
71.88
$
77.31
$
72.93
NGL ($/Bbl)
$
19.53
$
16.67
$
20.28
$
20.11
Quarter Ended June 30,
Six Months Ended June
30,
2024
2023
2024
2023
AVERAGE SALES PRICE (including
hedges)
Total Company
Natural gas ($/Mcf)
$
1.40
$1.95
$
1.76
$
2.81
Oil ($/Bbl)
$
79.39
$72.17
$
77.25
$
73.11
NGL ($/Bbl)
$
19.53
$16.67
$
20.28
$
20.11
Quarter Ended June
30,
Six Months Ended June
30,
2024
2023
2024
2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale
8
16
22
36
Permian Basin
63
33
111
72
Anadarko Basin
11
11
19
17
82
60
152
125
Net wells
Marcellus Shale
8.0
16.0
21.0
36.0
Permian Basin
26.8
21.3
50.0
37.9
Anadarko Basin
7.0
5.1
13.7
8.4
41.8
42.4
84.7
82.3
TURN IN LINES
Gross wells (2)
Marcellus Shale
12
20
23
45
Permian Basin
56
34
98
79
Anadarko Basin
26
3
31
7
94
57
152
131
Net wells (2)
Marcellus Shale
12.0
20.0
23.0
45.0
Permian Basin
22.6
19.1
44.5
42.2
Anadarko Basin
15.2
—
15.3
0.1
49.8
39.1
82.8
87.3
AVERAGE RIG COUNTS
Marcellus Shale
1.2
3.0
1.6
3.0
Permian Basin
8.0
6.0
8.0
6.0
Anadarko Basin
1.3
2.0
1.7
1.5
(1)
Wells drilled represents wells drilled to
total depth during the period.
(2)
The 12 turn-in lines in the Marcellus
Shale were brought online for less than 10 days on average in order
to de-water the developments. These wells were subsequently shut-in
or heavily curtailed and contributed negligible volumes during the
quarter (a total of 18 MMcf/d, or less than 0.1% of total company
gas volumes during the quarter). The wells were returned online in
early July.
Quarter Ended June
30,
Six Months Ended June
30,
2024
2023
2024
2023
AVERAGE UNIT COSTS ($/Boe) (1)
Direct operations
$
2.62
$
2.16
$
2.56
$
2.24
Gathering, processing and
transportation
3.99
4.27
3.99
4.20
Taxes other than income
0.89
1.05
1.04
1.27
General and administrative (excluding
stock-based compensation and severance expense)
0.85
0.79
0.92
0.85
Unit Operating Cost
$
8.35
$
8.27
$
8.52
$
8.56
Depreciation, depletion and
amortization
7.34
6.54
7.12
6.50
Exploration
0.09
0.09
0.08
0.08
Stock-based compensation
0.26
0.11
0.24
0.19
Severance expense
—
0.05
—
0.09
Interest expense, net
0.23
0.09
0.15
0.09
$
16.26
$
15.15
$
16.10
$
15.51
(1)
Total unit costs may differ from the sum
of the individual costs due to rounding.
Derivatives
Information
As of June 30, 2024, the Company had the
following outstanding financial commodity derivatives:
2024
Natural Gas
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
45,080,000
28,890,000
Weighted average floor ($/MMBtu)
$
2.75
$
2.75
Weighted average ceiling ($/MMBtu)
$
3.94
$
4.68
2025
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX collars
Volume (MMBtu)
27,000,000
27,300,000
27,600,000
27,600,000
Weighted average floor ($/MMBtu)
$
2.92
$
2.92
$
2.92
$
2.92
Weighted average ceiling ($/MMBtu)
$
5.12
$
4.37
$
4.37
$
6.20
2026
Natural Gas
First Quarter
NYMEX collars
Volume (MMBtu)
18,000,000
Weighted average floor ($/MMBtu)
$
2.75
Weighted average ceiling ($/MMBtu)
$
8.30
2024
2025
Oil
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
WTI oil collars
Volume (MBbl)
3,220
3,220
1,800
1,820
Weighted average floor ($/Bbl)
$
65.00
$
65.00
$
62.50
$
62.50
Weighted average ceiling ($/Bbl)
$
87.01
$
87.01
$
81.67
$
81.67
WTI Midland oil basis swaps
Volume (MBbl)
4,600
4,600
1,800
1,820
Weighted average differential ($/Bbl)
$
1.13
$
1.13
$
1.24
$
1.24
In July 2024, the Company entered into the
following financial commodity derivatives:
2025
Oil
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
Volume (MBbl)
900
910
1,380
1,380
Weighted average floor ($/Bbl)
$
65.00
$
65.00
$
65.00
$
65.00
Weighted average ceiling ($/Bbl)
$
84.07
$
84.07
$
83.18
$
83.18
WTI Midland oil basis swaps
Volume (MBbl)
900
910
1,380
1,380
Weighted average differential ($/Bbl)
$
1.13
$
1.13
$
1.14
$
1.14
CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended
Six Months Ended
June 30,
June 30,
(In millions,
except per share amounts)
2024
2023
2024
2023
OPERATING REVENUES
Oil
$
774
$
626
$
1,475
$
1,241
Natural gas
319
436
857
1,258
NGL
176
129
349
306
Gain (loss) on derivative instruments
(16
)
(12
)
(16
)
126
Other
18
6
39
31
1,271
1,185
2,704
2,962
OPERATING EXPENSES
Direct operations
160
130
316
264
Gathering, processing and
transportation
242
258
492
494
Taxes other than income
54
63
128
149
Exploration
5
5
10
9
Depreciation, depletion and
amortization
447
395
879
764
General and administrative (excluding
stock-based compensation and severance expense)
52
48
114
100
Stock-based compensation
16
7
29
23
Severance expense
—
3
—
11
976
909
1,968
1,814
Gain on sale of assets
1
—
—
5
INCOME FROM OPERATIONS
296
276
736
1,153
Interest expense
34
16
53
33
Interest income
(19
)
(10
)
(35
)
(22
)
Income before income taxes
281
270
718
1,142
Income tax expense
61
61
146
256
NET INCOME
$
220
$
209
$
572
$
886
Earnings per share - Basic
$
0.30
$
0.28
$
0.77
$
1.16
Weighted-average common shares
outstanding
742
755
746
760
CONDENSED CONSOLIDATED BALANCE SHEET
(Unaudited)
(In
millions)
June 30, 2024
December 31,
2023
ASSETS
Cash and cash equivalents
$
1,070
$
956
Short-term investments
250
—
Other current assets
1,017
1,059
Properties and equipment, net (successful
efforts method)
17,996
17,933
Other assets
431
467
$
20,764
$
20,415
LIABILITIES, REDEEMABLE PREFERRED STOCK
AND STOCKHOLDERS' EQUITY
Current liabilities
$
1,090
$
1,085
Current portion of long-term debt
575
575
Long-term debt, net (excluding current
maturities)
2,071
1,586
Deferred income taxes
3,390
3,413
Other long term liabilities
601
709
Cimarex redeemable preferred stock
8
8
Stockholders’ equity
13,029
13,039
$
20,764
$
20,415
CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended June 30,
Six Months Ended June
30,
(In
millions)
2024
2023
2024
2023
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income
$
220
$
209
$
572
$
886
Depreciation, depletion and
amortization
447
395
879
764
Deferred income tax (benefit) expense
(1
)
4
(23
)
27
Gain on sale of assets
(1
)
—
—
(5
)
(Gain) loss on derivative instruments
16
12
16
(126
)
Net cash received in settlement of
derivative instruments
36
84
62
184
Stock-based compensation and other
13
7
25
24
Income charges not requiring cash
(5
)
(6
)
(9
)
(10
)
Changes in assets and liabilities
(167
)
(59
)
(108
)
396
Net cash provided by operating
activities
558
646
1,414
2,140
CASH FLOWS FROM INVESTING
ACTIVITIES
Capital expenditures for drilling,
completion and other fixed asset additions
(479
)
(592
)
(936
)
(1,075
)
Capital expenditures for leasehold and
property acquisitions
(2
)
(5
)
(3
)
(6
)
Purchases of short-term investments
—
—
(250
)
—
Proceeds from sale of assets
1
28
1
33
Net cash used in investing activities
(480
)
(569
)
(1,188
)
(1,048
)
CASH FLOWS FROM FINANCING
ACTIVITIES
Net proceeds from debt
—
—
499
—
Repayment of finance leases
(2
)
(1
)
(3
)
(3
)
Common stock repurchases
(140
)
(57
)
(290
)
(325
)
Dividends paid
(156
)
(152
)
(314
)
(588
)
Tax withholding on vesting of stock
awards
—
—
—
(1
)
Capitalized debt issuance costs
—
—
(5
)
(7
)
Cash paid for conversion of redeemable
preferred stock
—
—
—
(1
)
Cash received for stock option
exercises
1
—
1
—
Net cash used in financing activities
(297
)
(210
)
(112
)
(925
)
Net increase (decrease) in cash, cash
equivalents and restricted cash
$
(219
)
$
(133
)
$
114
$
167
Reconciliation of Incurred Capital
Expenditures
Incurred capital expenditures is defined as capital expenditures
for drilling, completion and other fixed asset additions less
changes in accrued capital costs.
Quarter Ended June 30,
Six Months Ended June
30,
(In
millions)
2024
2023
2024
2023
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions (GAAP)
$
479
$
592
$
936
$
1,075
Change in accrued capital costs
(2
)
(55
)
(9
)
30
Incurred capital expenditures for
drilling, completion and other fixed asset additions (non-GAAP)
$
477
537
$
927
$
1,105
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 June 30,
Six Months Ended June
30,
(In millions,
except per share amounts)
2024
2023
2024
2023
As reported - net income
$
220
$
209
$
572
$
886
Reversal of selected items:
Gain on sale of assets
(1
)
—
—
(5
)
(Gain) loss on derivative
instruments(1)
52
96
78
58
Stock-based compensation expense
16
7
29
23
Severance expense
—
3
—
11
Tax effect on selected items
(15
)
(24
)
(24
)
(20
)
Adjusted net income
$
272
$
291
$
655
$
953
As reported - earnings per share
$
0.30
$
0.28
$
0.77
$
1.16
Per share impact of selected items
0.07
0.11
0.11
0.09
Adjusted earnings per share
$
0.37
$
0.39
$
0.88
$
1.25
Weighted-average common shares
outstanding
742
755
746
760
(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 June 30,
Six Months Ended June
30,
(In
millions)
2024
2023
2024
2023
Cash flow from operating activities
$
558
$
646
$
1,414
$
2,140
Changes in assets and liabilities
167
59
108
(396
)
Discretionary cash flow
725
705
1,522
1,744
Cash paid for capital expenditures for
drilling, completion and other fixed asset additions
(479
)
(592
)
(936
)
(1,075
)
Free cash flow
$
246
$
113
$
586
$
669
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 June 30,
Six Months Ended June
30,
(In
millions)
2024
2023
2024
2023
Net income
$
220
$
209
$
572
$
886
Plus (less):
Interest expense
34
16
53
33
Interest income
(19
)
(10
)
(35
)
(22
)
Income tax expense
61
61
146
256
Depreciation, depletion and
amortization
447
395
879
764
Exploration
5
5
10
9
Gain on sale of assets
(1
)
—
—
(5
)
Non-cash loss on derivative
instruments
52
96
78
58
Severance expense
—
3
—
11
Stock-based compensation
16
7
29
23
Adjusted EBITDAX
$
815
$
782
$
1,732
$
2,013
Trailing Twelve Months
Ended
(In
millions)
June 30, 2024
December 31,
2023
Net income
$
1,311
$
1,625
Plus (less):
Interest expense
93
73
Interest income
(60
)
(47
)
Income tax expense
393
503
Depreciation, depletion and
amortization
1,756
1,641
Exploration
21
20
Gain on sale of assets
(7
)
(12
)
Non-cash loss on derivative
instruments
75
54
Severance expense
1
12
Stock-based compensation
65
59
Adjusted EBITDAX (trailing twelve
months)
$
3,648
$
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)
June 30, 2024
December 31,
2023
Current portion of long-term debt
$
575
$
575
Long-term debt, net
2,071
1,586
Total debt
2,646
2,161
Stockholders’ equity
13,029
13,039
Total capitalization
$
15,675
$
15,200
Total debt
$
2,646
$
2,161
Less: Cash and cash equivalents
(1,070
)
(956
)
Less: Short-term investments
(250
)
—
Net debt
$
1,326
$
1,205
Net debt
$
1,326
$
1,205
Stockholders’ equity
13,029
13,039
Total adjusted capitalization
$
14,355
$
14,244
Total debt to total capitalization
ratio
16.9
%
14.2
%
Less: Impact of cash and cash
equivalents
7.7
%
5.7
%
Net debt to adjusted capitalization
ratio
9.2
%
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)
June 30, 2024
December 31,
2023
Total debt
$
2,646
$
2,161
Net income
1,311
1,625
Total debt to net income ratio
2.0 x
1.3 x
Net debt (as defined above)
$
1,326
$
1,205
Adjusted EBITDAX (Trailing twelve
months)
3,648
3,928
Net debt to Adjusted EBITDAX
0.4 x
0.3 x
2024 Guidance
The tables below present full-year and second quarter 2024
guidance.
Full Year Guidance
2024 Guidance (May)
Updated 2024 Guidance
Low Mid High
Low Mid High
Total Equivalent Production (MBoed)
635 - 655 - 675
645 - 660 - 675
Gas (Mmcf/day)
2,650 - 2,725 - 2,800
2,675 - 2,725 - 2,775
Oil (MBbl/day)
102.0 - 104.5 - 107.0
105.5 - 107.0 - 108.5
Net wells turned in line
Marcellus Shale
37 - 40 - 43
No change
Permian Basin
75 - 83 - 90
80 - 85 - 90
Anadarko Basin
20 - 23 - 25
21 - 24 - 27
Incurred capital expenditures ($ in
millions)
Total Company
$1,750 - $1,850 - $1,950
No change
Drilling and completion
Marcellus Shale
$350- $375 -$400
$375 midpoint
Permian Basin
$945 - $1,000 - $1,055
$1,000 midpoint
Anadarko Basin
$270 - $290 - $320
$290 midpoint
Midstream, saltwater disposal and
infrastructure
$185 - $185 - $185
$185 midpoint
Commodity price assumptions:
WTI ($ per bbl)
$79
$80
Henry Hub ($ per mmbtu)
$2.35
$2.37
Cash Flow & Investment ($ in
billions)
Discretionary Cash Flow
$3.1
$3.2
Incurred Capital Expenditures
$1.75 - $1.85 - $1.95
No change
Free Cash Flow (DCF - cash capex)
$1.3
$1.3
$ 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 - $9.55
No change
(1)
Excludes stock-based compensation and
severance expense
Quarterly Guidance
Second Quarter 2024
Guidance
Second Quarter 2024
Actual
Third Quarter 2024
Guidance
Low Mid High
Low Mid High
Total Equivalent Production (MBoed)
625 - 640 - 655
669
620 - 635 - 650
Gas (Mmcf/day)
2,600 - 2,650 - 2,700
2,780
2,500 - 2,565 - 2,630
Oil (MBbl/day)
103.0 - 105.0 - 107.0
107.2
107.0 - 109.0 - 111.0
Net wells turned in line
Marcellus Shale
0 - 0 - 0
12
0 – 4 - 7
Permian Basin
15 - 23 - 30
23
15 - 20 - 25
Anadarko Basin
7-10-13
15
5
Incurred capital expenditures ($ in
millions)
Total Company
$470 - $510 - $550
$477
$450 - $480 - $530
View source
version on businesswire.com: https://www.businesswire.com/news/home/20240801776861/en/
Investor Contact Daniel Guffey - Vice President of
Finance, IR & Treasury 281.589.4875
Hannah Stuckey - Investor Relations Manager
281.589.4983
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