2024年9月30日までの9か月間に会社は許可しました。 2,192,947 restricted stock units to employees of the Company with a weighted average grant date value of $25.83 per unit. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest at the end of a 上限総元本$百万ドルの、上限なしの期間でのシニア無担保債務の借り入れクレジット施設（「Term Loan Facility」とともに、「Credit Facilities」といいます）； service period. The Company assumed a なし売上高 調整後 EBITDA の5日間 2024年に付与された株式報酬に対する認識のための年間売却率は、会社の実際の売却履歴およびこの種の報酬に対する期待に基づいています。
Restructuring costs are primarily related to workforce reductions and associated severance benefits that were triggered by the merger with Cimarex Energy Co. that closed on October 1, 2021. The following table summarizes the Company’s restructuring liabilities:
Nine Months Ended September 30,
(In millions)
2024
2023
Balance at beginning of period
$
47
$
77
Additions related to merger integration
—
10
Reductions related to severance payments
(27)
(28)
Balance at end of period
$
20
$
59
13. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following review of operations of Coterra Energy Inc. (“Coterra,” the “Company,” “our,” “we” and “us”) for the three and nine month periods ended September 30, 2024 and 2023 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Quarterly Report on Form 10-Q (this “Form 10-Q”) and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in our Annual Report on Form 10-K for the year ended December 31, 2023 filed on February 23, 2024 (our “Form 10-K”). For the abbreviations and definitions of certain terms commonly used in the oil and gas industry, please see the “Glossary of Certain Oil and Gas Terms” included within our Form 10-K.
OVERVIEW
Financial and Operating Overview
Financial and operating results for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 reflect the following:
•Net income decreased $71 million from $323 million, or $0.43 per share, in 2023 to $252 million, or $0.34 per share, in 2024.
•Net cash provided by operating activities decreased $3 million, from $758 million in 2023 to $755 million in 2024.
•Equivalent production remained flat at 61.6 MMBoe, or 669.1 MBoe per day, in 2024.
◦Oil production increased 1.8 MMBbl from 8.5 MMBbl, or 91.9 MBbl per day, in 2023 to 10.3 MMBbl, or 112.3 MBbl per day, in 2024.
◦Natural gas production decreased 20.4 Bcf from 267.1 Bcf, or 2,903.2 Mmcf per day, in 2023 to 246.7 Bcf, or 2,682.0 Mmcf per day, in 2024.
◦NGL volumes increased 1.4 MMBbl from 8.7 MMBbl, or 94.5 MBbl per day, in 2023 to 10.1 MMBbl, or 109.7 MBbl per day, in 2024.
•Average realized prices (including impact of derivatives):
◦Oil was $74.18 per Bbl in 2024, eight percent lower than the $80.74 per Bbl realized in 2023.
◦Natural gas was $1.41 per Mcf in 2024, 30 percent lower than the $2.01 per Mcf realized in 2023.
◦NGL price was $18.42 per Bbl in 2024, six percent lower than the $19.52 per Bbl realized in 2023.
•Total capital expenditures for drilling, completion and other fixed assets were $418 million in 2024 compared to $542 million in the corresponding period of the prior year.
Financial and operating results for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 reflect the following:
•Net income decreased $385 million from $1.2 billion, or $1.59 per share, in 2023 to $824 million, or $1.11 per share, in 2024.
•Net cash provided by operating activities decreased $729 million, from $2.9 billion in 2023 to $2.2 billion in 2024.
•Equivalent production increased 5.6 MMBoe from 179.3 MMBoe, or 656.9 MBoe per day, in 2023 to 184.9 MMBoe, or 674.8 MBoe per day in 2024.
◦Oil production increased 3.9 MMBbl from 25.5 MMBbl, or 93.3 MBbl per day, in 2023 to 29.4 MMBbl, or 107.4 MBbl per day, in 2024.
◦Natural gas production decreased 10.4 Bcf from 779.5 Bcf, or 2,855.3 Mmcf per day, in 2023 to 769.1 Bcf, or 2,806.8 Mmcf per day, in 2024.
◦NGL volumes increased 3.4 MMBbl from 23.9 MMBbl, or 87.7 MBbl per day, in 2023 to 27.3 MMBbl, or 99.6 MBbl per day, in 2024.
•Average realized prices (including impact of derivatives):
◦Oil was $76.17 per Bbl in 2024, one percent higher than the $75.64 per Bbl realized in 2023.
◦Natural gas was $1.65 per Mcf in 2024, 35 percent lower than the $2.53 per Mcf realized in 2023.
◦NGL price was $19.59 per Bbl in 2024, two percent lower than the $19.90 per Bbl realized in 2023.
•Total capital expenditures for drilling, completion and other fixed assets were $1.3 billion in 2024 compared to $1.6 billion in the corresponding period of the prior year.
Other financial highlights for the nine months ended September 30, 2024 include the following:
◦Issued $500 million aggregate principal amount of 5.60% senior notes due March 15, 2034. We used the net proceeds, and cash on hand, to repay the $575 million of 3.65% weighted-average private placement senior notes that matured in September 2024.
•Amended our revolving credit agreement to increase aggregate commitments from $1.5 billion to $2.0 billion and extend the maturity date from March 2028 to September 2029.
•Increased our quarterly base dividend from $0.20 per share to $0.21 per share in February 2024.
•Repurchased 15 million shares for $404 million.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which can be impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, and geopolitical, economic and other factors.
Oil prices have recovered in recent years from previous pandemic-related market weakness, particularly on the demand side. Global conflict and supply chain disruptions drove high oil prices in 2022, which then moderated throughout 2023. OPEC+ reacted with supply reductions, helping to stabilize oil price levels during 2023. U.S. oil production has been flat, which, when combined with OPEC+’s reductions, has contributed to relatively steadier oil prices in 2023 and 2024.
Natural gas prices have trended down year-over-year as strong production and relatively weak demand drove inventory levels above the five-year average. While natural gas prices have increased from their lows in early 2024, natural gas prices in 2024 have still trended lower overall compared to 2023. In response to the weakness of natural gas prices, we strategically curtailed our production in the Marcellus Shale during 2024, resulting in an estimated curtailment of 275 MMcf per day of gross production. Natural gas prices are expected to experience a slight increase throughout the remainder of 2024 and into early 2025 due to, among other factors, forecasted colder temperatures resulting in increased seasonal demand. Meanwhile, basis differentials have become more divergent in 2024, in part due to constrained pipeline capacity and oversupply in certain geographic areas, and at times have resulted in negative spot market pricing this year for natural gas, such as in the Permian Basin at the Waha Hub. Looking towards 2025, recent NYMEX strip pricing indicates the forecasted increase in natural gas prices overall is expected to continue, partially as a result of, among other factors, an expected increase in demand driven by LNG exports.
Although the current outlook on oil and natural gas prices is generally favorable and our operations have not been significantly impacted in the short-term, in the event further disruptions occur and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline, and our costs could increase. We expect commodity price volatility to continue, driven by further geopolitical disruptions, including conflicts in the Middle East and actions of OPEC+ and potentially swift near- and medium-term fluctuations in supply and demand. While we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future. However, in the event that commodity prices significantly decline or costs significantly increase from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.
In addition, the issue of, and increasing political and social attention on, climate change has resulted in both existing and pending national, regional and local legislation and regulatory measures, such as mandates for renewable energy and emissions reductions. Changes in these laws or regulations may result in delays or restrictions in permitting and the development of projects, may result in increased costs and may impair our ability to move forward with our construction, completions, drilling,
water management, waste handling, storage, transport and remediation activities, any of which could have an adverse effect on our financial results.
For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below.
Outlook
Our 2024 full year capital program is expected to be approximately $1.75 billion to $1.85 billion. We expect to fund these capital expenditures with our operating cash flow. We expect to turn-in-line 141 to 157 total net wells in 2024 across our three operating regions. Approximately 64 percent of our drilling and completion capital is expected to be invested in the Permian Basin, 18 percent in the Marcellus Shale and 18 percent in the Anadarko Basin.
In 2023, we drilled 264 gross wells (169.4 net) and turned-in-line 273 gross wells (173.0 net). For the nine months ended September 30, 2024, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 120.9 net wells and turned in line 118.3 net wells. Our capital program for the remainder of 2024 will focus on execution of our 2024 plan presented in our annual guidance. In the normal course of our business, we will continue to assess the oil and natural gas price macro environments and may adjust our capital allocation accordingly.
FINANCIAL CONDITION
Liquidity and Capital Resources
We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our liquidity requirements consist primarily of our planned capital expenditures, payment of contractual obligations (including debt maturities and interest payments), working capital requirements, dividend payments and share repurchases. Although we have no obligation to do so, we may also from time-to-time refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise.
Our primary sources of liquidity are cash on hand, net cash provided by operating activities and available borrowing capacity under our revolving credit agreement. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand. However, from time-to-time, our investments may be funded by bank borrowings (including draws on our revolving credit agreement), sales of assets, and private or public financing based on our monitoring of capital markets and our balance sheet. While there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities if our debt rating falls below a certain level, a change in our debt rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates and fees for unused commitments under our revolving credit agreement, see Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K, “Long-Term Debt and Credit Agreements.” We believe that, with operating cash flow, cash on hand and availability under our revolving credit agreement, we have the ability to finance our spending plans over the next 12 months and, based on current expectations, for the longer term.
Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit agreement, borrowings and repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time-to-time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. As of September 30, 2024 and December 31, 2023, we had a working capital surplus of $655 million and $355 million, respectively. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements over the next 12 months.
In September 2024, we entered into an amendment relating to our revolving credit agreement, which increased our aggregate commitments from $1.5 billion to $2.0 billion and extended the maturity date to September 2029, among other things.
As of September 30, 2024, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $2.0 billion, and we had unrestricted cash on hand of $843 million.
In March 2024, we issued $500 million of 5.60% senior notes, and used these net proceeds, along with cash on hand, to fund the repayment of the $575 million of 3.65% weighted-average senior notes that matured in September 2024.
Our revolving credit agreement includes a covenant limiting our borrowing capacity based on our leverage ratio. As of September 30, 2024, we were in compliance with all financial covenants applicable to our revolving credit agreement and private placement senior notes. Refer to Note 3 of the Notes to the Condensed Consolidated Financial Statements in this report, “Long-Term Debt and Credit Agreements” and Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K, “Long-Term Debt and Credit Agreements,” for further details.
Cash Flows
Our cash flows from operating activities, investing activities and financing activities were as follows:
Nine Months Ended September 30,
(In millions)
2024
2023
Cash flows provided by operating activities
$
2,169
$
2,898
Cash flows used in investing activities
(1,327)
(1,589)
Cash flows used in financing activities
(959)
(1,136)
Net (decrease) increase in cash, cash equivalents and restricted cash
$
(117)
$
173
Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. As stated above, commodity prices have historically been volatile. Fluctuations in cash flow may result in an increase or decrease in our capital expenditures.
Net cash provided by operating activities for the nine months ended September 30, 2024 decreased by $729 million compared to the same period in 2023. This decrease was primarily due to a decrease in natural gas revenue, caused by lower natural gas prices and production, an increase in operating costs, a decrease in cash received on derivative settlements and a net reduction in working capital during 2024. These decreases were partially offset by an increase in oil revenues.
Refer to “Results of Operations” below for additional information relative to commodity prices, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.
Investing Activities. Cash flows used in investing activities decreased by $262 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. This decrease was primarily due to $294 million lower cash paid for capital expenditures, partially offset by $32 million lower proceeds from asset sales.
Financing Activities. Cash flows used in financing activities decreased by $177 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. This decrease was due to the issuance of the $500 million of 5.60% senior notes during the first quarter of 2024 and $269 million of lower dividend payments. These decreases were partially offset by the repayment of $575 million of 3.65% weighted-average senior notes at their maturity in September 2024 and $16 million of increased common stock repurchases. The lower dividend payments were a result of a decrease in our dividend rate from $0.97 per common share (base-plus-variable) for the nine months ended September 30, 2023 to $0.63 per common share (base only) for the nine months ended September 30, 2024, and a decrease in outstanding shares of common stock due to our active share repurchase program during 2023 and the first nine months of 2024.
Capitalization
Information about our capitalization is as follows:
(1) Included $575 million of current portion of long-term debt as of December 31, 2023 that was repaid at maturity in September 2024. There were no borrowings outstanding under our revolving credit agreement as of September 30, 2024 and December 31, 2023.
Share repurchases. During the nine months ended September 30, 2024, we repurchased and retired 15 million shares of our common stock for $404 million. We repurchased and retired 15 million shares of our common stock for $388 million during the nine months ended September 30, 2023.
Dividends. In February 2024, our Board of Directors approved an increase in the base quarterly dividend from $0.20 per share to $0.21 per share.
The following table summarizes our dividends on our common stock:
Rate Per Share
Total Dividends (In millions)
Base
Variable
Total
2024
First quarter
$
0.21
$
—
$
0.21
$
160
Second quarter
0.21
—
0.21
158
Third quarter
0.21
—
0.21
156
$
0.63
$
—
$
0.63
$
474
2023
First quarter
$
0.20
$
0.37
$
0.57
$
438
Second quarter
0.20
—
0.20
153
Third quarter
0.20
—
0.20
153
$
0.60
$
0.37
$
0.97
$
744
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash flow provided by operating activities, and, if required, borrowings under our revolving credit agreement. We budget these expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures:
Nine Months Ended September 30,
(In millions)
2024
2023
Capital expenditures:
Drilling and facilities
$
1,261
$
1,537
Pipeline and gathering
73
84
Other
11
26
Capital expenditures for drilling, completion and other fixed asset additions
1,345
1,647
Capital expenditures for leasehold and property acquisitions
(1)Exploration expenditures include $5 million of exploratory dry hole costs for the ninemonths ended September 30, 2024. There were no exploratory dry hole costs for the nine months ended September 30, 2023.
For the nine months ended September 30, 2024, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 120.9 net wells and turned-in-line 118.3 net wells. We continue to expect that our full-year 2024 capital program will be approximately $1.75 billion to $1.85 billion. Refer to “Outlook” above for additional information regarding the current year drilling program. We will continue to assess the commodity price environment and may adjust our capital expenditures accordingly.
Contractual Obligations
We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Gathering, Processing and Transportation Agreements” and “Lease Commitments” as disclosed in Note 8 of the Notes to the Consolidated Financial Statements and the obligations described under “Contractual
Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Refer to our Form 10-K for further discussion of our critical accounting policies.
RESULTS OF OPERATIONS
Third Quarters of 2024 and 2023 Compared
Operating Revenues
Three Months Ended September 30,
Variance
(In millions)
2024
2023
Amount
Percent
Operating Revenues
Oil
$
765
$
684
$
81
12
%
Natural gas
320
481
(161)
(33)
%
NGL
186
170
16
9
%
Gain on derivative instruments
64
3
61
2,033
%
Other
24
18
6
33
%
$
1,359
$
1,356
$
3
—
%
Production Revenues
Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which, as discussed above, fluctuate.
The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.
Three Months Ended September 30,
Variance
2024
2023
Amount
Percent
Production Volumes
Oil (MMBbl)
10.3
8.5
1.8
21
%
Natural gas (Bcf)
246.7
267.1
(20.4)
(8)
%
NGL (MMBbl)
10.1
8.7
1.4
16
%
Average Daily Production Volumes
Oil (MBbl)
112.3
91.9
20.4
22
%
Natural gas (MMcf)
2,682.0
2,903.2
(221.2)
(8)
%
NGL (MBbl)
109.7
94.5
15.2
16
%
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)
$
74.04
$
80.80
$
(6.76)
(8)
%
Natural gas ($/Mcf)
$
1.30
$
1.80
$
(0.50)
(28)
%
NGL ($/Bbl)
$
18.42
$
19.52
$
(1.10)
(6)
%
Including Derivative Settlements
Oil ($/Bbl)
$
74.18
$
80.74
$
(6.56)
(8)
%
Natural gas ($/Mcf)
$
1.41
$
2.01
$
(0.60)
(30)
%
NGL ($/Bbl)
$
18.42
$
19.52
$
(1.10)
(6)
%
Oil Revenues
Three Months Ended September 30,
Variance
Increase (Decrease) (In millions)
2024
2023
Amount
Percent
Volume (MMBbl)
10.3
8.5
1.8
21
%
$
151
Price ($/Bbl)
$
74.04
$
80.80
$
(6.76)
(8)
%
(70)
$
81
Oil revenues increased $81 million due to higher production in the Permian Basin and Anadarko Basin, partially offset by lower oil prices.
Natural Gas Revenues
Three Months Ended September 30,
Variance
Increase (Decrease) (In millions)
2024
2023
Amount
Percent
Volume (Bcf)
246.7
267.1
(20.4)
(8)
%
$
(37)
Price ($/Mcf)
$
1.30
$
1.80
$
(0.50)
(28)
%
(124)
$
(161)
Natural gas revenues decreased $161 million primarily due to significantly lower natural gas prices and lower production. The decrease in production was related to lower production in the Marcellus Shale, where we strategically curtailed production due to weaker natural gas prices. This decrease was partially offset by higher production in the Permian and Anadarko Basins.
NGL revenues increased $16 million primarily due to higher NGL volumes in the Permian Basin, partially offset by lower prices.
Gain on Derivative Instruments
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows.
The following table presents the components of “Gain on derivative instruments” for the periods indicated:
Three Months Ended September 30,
(In millions)
2024
2023
Cash received on settlement of derivative instruments
Gas contracts
$
27
$
55
Oil contracts
1
—
Non-cash gain (loss) on derivative instruments
Gas contracts
(12)
(40)
Oil contracts
48
(12)
$
64
$
3
Operating Costs and Expenses
Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies had begun to stabilize at the end of 2023 despite the on-going demand for those items and the latent effects of inflation and supply chain disruptions, and thus far in 2024 these costs have remained stable.
The following table reflects our operating costs and expenses for the periods indicated and a discussion of the operating costs and expenses follows.
Three Months Ended September 30,
Variance
Per BOE
(In millions, except per BOE)
2024
2023
Amount
Percent
2024
2023
Operating Expenses
Direct operations
$
165
$
137
$
28
20
%
$
2.69
$
2.22
Gathering, processing and transportation
245
235
10
4
%
3.97
3.81
Taxes other than income
66
62
4
6
%
1.08
1.00
Exploration
9
5
4
80
%
0.15
0.08
Depreciation, depletion and amortization
475
421
54
13
%
7.73
6.82
General and administrative
75
79
(4)
(5)
%
1.24
1.29
$
1,035
$
939
$
96
10
%
Direct Operations
Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include well workover activity necessary to maintain production from existing wells.
Direct operations expense consisted of lease operating expense and workover expense as follows:
Three Months Ended September 30,
Per BOE
(In millions, except per BOE)
2024
2023
Variance
2024
2023
Direct Operations Expense
Lease operating expense
$
138
$
115
$
23
$
2.25
$
1.86
Workover expense
27
22
5
0.44
0.36
$
165
$
137
$
28
$
2.69
$
2.22
Lease operating expense increased primarily due to higher operating costs driven by our production mix related to increased production in fields with higher operating costs and higher equipment and field service costs.
Gathering, Processing and Transportation
Gathering, processing and transportation costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression, along with processing costs, which are incurred to extract NGLs from the raw natural gas stream. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.
Gathering, processing and transportation costs increased $10 million primarily due to higher gathering and transportation costs in the Permian Basin related to higher transportation rates and higher production, partially offset by lower gathering charges in the Marcellus Shale related to lower production.
Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties.
The following table presents taxes other than income for the periods indicated:
Three Months Ended September 30,
(In millions)
2024
2023
Variance
Taxes Other than Income
Production
$
53
$
45
$
8
Drilling impact fees
4
5
(1)
Ad valorem
9
11
(2)
Other
—
1
(1)
$
66
$
62
$
4
Production taxes as percentage of revenue (Permian and Anadarko Basins)
5.5
%
4.7
%
Taxes other than income increased primarily due to an increase in our production taxes primarily due to higher oil and NGL revenues in 2024 compared to 2023.
Exploration
Exploration expense increased primarily due to $5 million of exploratory dry hole costs recognized during the three months ended September 30, 2024.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A expense consisted of the following for the periods indicated:
Three Months Ended September 30,
Per BOE
(In millions, except per BOE)
2024
2023
Variance
2024
2023
DD&A Expense
Depletion
$
443
$
387
$
56
$
7.19
$
6.27
Depreciation
18
19
(1)
0.32
0.31
Amortization of unproved properties
12
12
—
0.19
0.19
Accretion of ARO
2
3
(1)
0.03
0.05
$
475
$
421
$
54
$
7.73
$
6.82
Depletion of our producing properties is computed on a field basis using the units-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and natural gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $56 million primarily due to a higher depletion rate which was driven by lower oil and gas reserve volumes and a shift in our production mix which resulted in increased production from fields with higher depletion rates. The lower oil and gas reserve volumes were driven by negative price revisions as a result of lower prices in 2023.
Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method
based on expected lives of the individual assets, which range from three to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system.
Unproved properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made.
General and Administrative (“G&A”)
G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred.
The table below reflects our G&A expense for the periods indicated:
Three Months Ended September 30,
(In millions)
2024
2023
Variance
G&A Expense
General and administrative expense
$
61
$
59
$
2
Stock-based compensation expense
14
21
(7)
Merger-related expense
—
(1)
1
$
75
$
79
$
(4)
Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Stock-based compensation expense decreased $7 million primarily due to a decrease in the valuation of performance share awards in 2024 compared to 2023.
Interest Expense
The table below reflects our interest expense for the periods indicated:
Three Months Ended September 30,
(In millions)
2024
2023
Variance
Interest Expense
Interest expense
$
27
$
20
$
7
Debt premium and discount amortization, net
(5)
(4)
(1)
Debt issuance cost amortization
1
1
—
Other
1
—
1
$
24
$
17
$
7
Interest expense increased primarily due to higher debt balances during the third quarter of 2024 compared to 2023.
Interest Income
Interest income increased $6 million due to higher interest earned on our higher cash and short-term investment balances.
Combined federal and state effective income tax rate
21.0
%
22.5
%
Income tax expense decreased $27 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, primarily due to lower pre-tax income and a lower effective tax rate.
The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.
Nine Months Ended September 30,
Variance
2024
2023
Amount
Percent
Production Volumes
Oil (MMBbl)
29.4
25.5
3.9
15
%
Natural gas (Bcf)
769.1
779.5
(10.4)
(1)
%
NGL (MMBbl)
27.3
23.9
3.4
14
%
Average Daily Production Volumes
Oil (MBbl)
107.4
93.3
14.1
15
%
Natural gas (MMcf)
2,806.8
2,855.3
(48.5)
(2)
%
NGL (MBbl)
99.6
87.7
11.9
14
%
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)
$
76.16
$
75.54
$
0.62
1
%
Natural gas ($/Mcf)
$
1.53
$
2.23
$
(0.70)
(31)
%
NGL ($/Bbl)
$
19.59
$
19.90
$
(0.31)
(2)
%
Including Derivative Settlements
Oil ($/Bbl)
$
76.17
$
75.64
$
0.53
1
%
Natural gas ($/Mcf)
$
1.65
$
2.53
$
(0.88)
(35)
%
NGL ($/Bbl)
$
19.59
$
19.90
$
(0.31)
(2)
%
Oil Revenues
Nine Months Ended September 30,
Variance
Increase (Decrease) (In millions)
2024
2023
Amount
Percent
Volume (MMBbl)
29.4
25.5
3.9
15
%
$
297
Price ($/Bbl)
$
76.16
$
75.54
$
0.62
1
%
18
$
315
Oil revenues increased $315 million primarily due to higher production in the Permian Basin.
Natural Gas Revenues
Nine Months Ended September 30,
Variance
Increase (Decrease) (In millions)
2024
2023
Amount
Percent
Volume (Bcf)
769.1
779.5
$
(10.4)
(1)
%
$
(24)
Price ($/Mcf)
$
1.53
$
2.23
$
(0.70)
(31)
%
(538)
$
(562)
Natural gas revenues decreased $562 million primarily due to significantly lower natural gas prices and lower production driven by the strategic curtailments of production in the Marcellus Shale during the third quarter due to weaker natural gas prices.
Lease operating expense increased primarily due to higher production levels and higher operating costs driven by our production mix related to increased production in fields with higher operating costs and higher equipment and field service costs.
Gathering, Processing and Transportation
Gathering, processing and transportation costs increased $8 million due to higher production in the Permian and Anadarko Basins, partially offset lower production in the Marcellus Shale and lower transportation rates in the Permian and Anadarko Basins.
Taxes Other Than Income
The following table presents taxes other than income for the periods indicated:
Nine Months Ended September 30,
(In millions)
2024
2023
Variance
Taxes Other than Income
Production
$
159
$
148
$
11
Drilling impact fees
11
18
(7)
Ad valorem
25
43
(18)
Other
(1)
2
(3)
$
194
$
211
$
(17)
Production taxes as percentage of revenue (Permian and Anadarko Basins)
5.6
%
5.5
%
Taxes other than income decreased $17 million primarily due to lower ad valorem taxes, which was primarily driven by a combination of lower expected property valuations in 2024 resulting in a lower tax obligation and a reduction of prior period accruals due to a change in estimated taxes due for the full-year 2023. Additionally, drilling impact fees decreased primarily due to a decrease in activity in the Marcellus Shale and lower natural gas prices. These decreases were partially offset by a slight increase in our production taxes, which increased primarily due to higher oil and NGL production compared to 2023.
Exploration
Exploration expense increased primarily due to $5 million of exploratory dry hole costs recognized in the third quarter of 2024.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A expense consisted of the following for the periods indicated:
Nine Months Ended September 30,
Per BOE
(In millions, except per Boe)
2024
2023
Variance
2024
2023
DD&A Expense
Depletion
$
1,256
$
1,086
$
170
$
6.79
$
6.06
Depreciation
54
55
(1)
0.30
0.31
Amortization of unproved properties
36
36
—
0.19
0.20
Accretion of ARO
8
8
—
0.04
0.04
$
1,354
$
1,185
$
169
$
7.32
$
6.61
Our depletion expense increased $170 million primarily due to an increase in our depletion rate and an increase in production. Our depletion rate increased due to lower oil and gas reserve volumes and a shift in our production mix which resulted in increased production from fields with higher depletion rates. The lower oil and gas reserve volumes were driven by negative price revisions as a result of lower prices in 2023.
The table below reflects our G&A expense for the periods indicated:
Nine Months Ended September 30,
(In millions)
2024
2023
Variance
G&A Expense
General and administrative expense
$
175
$
159
$
16
Stock-based compensation expense
43
44
(1)
Merger-related expense
—
10
(10)
$
218
$
213
$
5
G&A expense, excluding stock-based compensation and merger-related expenses, increased $16 million primarily due to the recognition of certain long-term commitments for community outreach and charitable contributions in 2024 and higher employee related costs in 2024 compared to 2023.
Stock-based compensation expense decreased $1 million primarily due to the impact of the liquidation of our common stock from our deferred compensation plan that resulted in a $7 million gain that decreased stock-based compensation expense in the first half of 2023, partially offset by awards that vested in 2023 and a decrease in the valuation of performance share awards in 2024 compared to 2023.
Merger-related expense decreased $10 million as the employee-related severance and termination benefits associated with the 2021 merger was accrued over the transition period during 2022 and 2023.
Interest Expense
The table below reflects our interest expense for the periods indicated:
Nine Months Ended September 30,
(In millions)
2024
2023
Variance
Interest Expense
Interest expense
$
76
$
61
$
15
Debt premium and discount amortization, net
(16)
(15)
(1)
Debt issuance cost amortization
3
3
—
Other
14
1
13
$
77
$
50
$
27
Interest expense increased $27 million primarily due to an increase of $15 million related to interest on debt balances, primarily due to the issuance of 5.60% senior notes in early March 2024 and an increase in other interest expense of $13 million related to assessments arising due to the timing of certain regulatory filings.
Interest Income
Interest income increased $19 million due to higher interest earned on our higher cash and short-term investment balances.
Combined federal and state effective income tax rate
20.5
%
22.4
%
Income tax expense decreased $137 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to lower pre-tax income and a lower effective tax rate.
Forward-Looking Information
This report includes forward-looking statements within the meaning of federal securities laws. All statements, other than statements of historical fact, included in this report are forward-looking statements. Such forward-looking statements include, but are not limited, statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, timing and amount of capital expenditures and other statements that are not historical facts contained in this report. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of OPEC+, 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 the conflict in the Middle East or further escalation thereof, results of future drilling and marketing activities, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches, the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, and other factors detailed herein and in our other SEC filings. Refer to “Risk Factors” in Item 1A of Part I of our Form 10-K for additional information about these risks and uncertainties. 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, we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.
Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the Investors section of our website (www.coterra.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of, and is not incorporated into, this report.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
In the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. Except as otherwise indicated, the following quantitative and qualitative information is provided about financial instruments to which we were party as of September 30, 2024 and from which we may incur future gains or losses from changes in commodity prices or interest rates.
Commodity Price Risk
Our most significant market risk exposure is pricing applicable to our oil, natural gas and NGL production. Realized prices are mainly driven by the worldwide price for oil and spot market prices for North American natural gas and NGL production. As noted above, these prices have been volatile and unpredictable. To mitigate the volatility in commodity prices, we may enter into derivative instruments to hedge a portion of our production.
Derivative Instruments and Risk Management Activities
Our commodity price risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees these risk management activities. Our financial commodity derivatives generally cover a portion of our production and, while protecting us in the event of price declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 4 in this Form 10-Q and Note 5 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivatives.
Periodically, we enter into financial commodity derivatives, including collar, swap and basis swap agreements, to protect against exposure to commodity price declines. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas in exchange for paying a variable price based on a market-based index.
As of September 30, 2024, we had the following outstanding financial commodity derivatives:
2024
2025
Fair Value Asset (Liability) (in millions)
Oil
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
WTI oil collars
$
36
Volume (MBbl)
3,680
3,330
3,367
2,024
2,024
Weighted average floor ($/Bbl)
$
65.00
$
61.89
$
61.89
$
62.05
$
62.05
Weighted average ceiling ($/Bbl)
$
86.20
$
81.40
$
81.40
$
81.15
$
81.15
WTI Midland oil basis swaps
3
Volume (MBbl)
4,600
3,150
3,185
1,840
1,840
Weighted average differential ($/Bbl)
$
1.13
$
1.18
$
1.18
$
1.11
$
1.11
$
39
2024
2025
2026
Fair Value Asset (Liability) (in millions)
Natural Gas
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
First Quarter
NYMEX collars
$
11
Volume (MMBtu)
34,990,000
36,000,000
36,400,000
36,800,000
36,800,000
27,000,000
Weighted average floor ($/MMBtu)
$
2.75
$
2.88
$
2.88
$
2.88
$
2.88
$
2.75
Weighted average ceiling ($/MMBtu)
$
4.46
$
4.70
$
4.15
$
4.15
$
6.00
$
7.66
$
11
In October 2024, we 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
A significant portion of our expected oil and natural gas production for the remainder of 2024 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable.
During the nine months ended September 30, 2024, oil collars with floor prices ranging from $65.00 to $70.00 per Bbl and ceiling prices ranging from $80.55 to $92.40 per Bbl covered 9.6 MMBbls, or 33 percent, of our oil production at a weighted-average price of $66.71 per Bbl. Oil basis swaps covered 10.9 MMBbls, or 37 percent, of our oil production at a weighted-average price of $1.14 per Bbl.
During the nine months ended September 30, 2024, natural gas collars with floor prices ranging from $2.50 to $3.00 per MMBtu and ceiling prices ranging from $2.85 to $5.67 per MMBtu covered 122.5 Mcf, or 16 percent of our natural gas production at a weighted-average price of $2.80 per MMBtu.
We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of the related commodity. However, the market risk exposure on these derivative contracts is generally offset by the gain on or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that our management believes present minimal credit risk, and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties, and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.
Interest Rate Risk
As of September 30, 2024, we had total debt of $2,066 million (with a principal amount of $2,000 million). All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates with respect to such debt. Our revolving credit agreement provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of September 30, 2024 and, therefore, we have no related exposure to interest rate risk.
Fair Value of Other Financial Instruments
The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash, cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments.
The fair value of our senior notes is based on quoted market prices. The fair value of our private placement senior notes is based on third-party quotes which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs.
The carrying amount and estimated fair value of debt are as follows:
September 30, 2024
December 31, 2023
(In millions)
Carrying Amount
Estimated Fair Value
Carrying Amount
Estimated Fair Value
Total debt
$
2,066
$
1,989
$
2,161
$
2,015
Current maturities
—
—
(575)
(565)
Long-term debt, excluding current maturities
$
2,066
$
1,989
$
1,586
$
1,450
ITEM 4. Controls and Procedures
As of September 30, 2024, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
The information set forth under the heading “Legal Matters” in Note 7 of the Notes to Condensed Consolidated Financial Statements included in this Form 10-Q is incorporated by reference in response to this item.
Governmental Proceedings
From time-to-time, we receive notices of violation from governmental and regulatory authorities, including notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines, penalties or both, if fines or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $300,000.
In June 2023, we received a Notice of Violation and Opportunity to Confer (“NOVOC”) from the U.S. Environmental Protection Agency (“EPA”) alleging violations of the Clean Air Act, the Texas State Implementation Plan, the New Mexico State Implementation Plan (“NMSIP”) and certain other state and federal regulations pertaining to Company facilities in Texas and New Mexico. Separately, in July 2023, we received a letter from the U.S. Department of Justice that the EPA has referred this NOVOC for civil enforcement proceedings. In August 2023, we received a second NOVOC from the EPA alleging violations of the Clean Air Act, the NMSIP, and certain other state and federal regulations pertaining to Company facilities in New Mexico. We have exchanged information with the EPA and continue to engage in discussions aimed at resolving the allegations. At this time we are unable to predict with certainty the financial impact of these NOVOCs or the timing of any resolution. However, any enforcement action related to these NOVOCs will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs or operating costs. We believe that any fines, penalties, or corrective actions that may result from these matters will not have a material effect on our financial position, results of operations, or cash flows.
ITEM 1A. Risk Factors
For additional information about the risk factors that affect us, see Item 1A of Part I of our Form 10-K.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
Share repurchase activity during the quarter ended September 30, 2024 was as follows:
Period
Total Number of Shares Purchased (In thousands)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
(In thousands) (1)
Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (In millions)
(1) All purchases during the covered periods were made under the share repurchase program, which was approved by our Board of Directors in February 2023 and which authorized the repurchase of up to $2.0 billion of our common stock. The share repurchase program does not have an expiration date. Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1.
During the three months ended September 30, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COTERRA ENERGY INC.
(Registrant)
November 1, 2024
By:
/s/ THOMAS E. JORDEN
Thomas E. Jorden
Chairman, Chief Executive Officer and President
(Principal Executive Officer)
November 1, 2024
By:
/s/ SHANNON E. YOUNG III
Shannon E. Young III
Executive Vice President and Chief Financial Officer