COTERRA ENERGY INC. The following review of operations ofCoterra Energy Inc. ("Coterra," "our," "we" and "us") for the three month periods endedMarch 31, 2023 and 2022 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 endedDecember 31, 2022 (our "Form 10-K").
OVERVIEW
Financial and Operating Overview
Financial and operating results for the three months ended
•Equivalent production increased 0.5 MMBoe from 56.7 MMBoe, or 629.9 MBoepd, in 2022 to 57.2 MMBoe, or 635.0 MBoepd in 2023. The slight increase was attributable to increased production in the Permian and Anadarko Basins, partially offset by lower production in theMarcellus Shale due to the timing of our 2023 drilling and completion activities. •Natural gas production decreased 8.3 Bcf from 256.4 Bcf, or 2,850 Mmcf per day, in 2022 to 248.1 Bcf, or 2,757 Mmcf per day, in the 2023 period. The decrease was primarily attributable to lower production in theMarcellus Shale due to the timing of our drilling and completion activities. •Oil production increased 0.8 MMBbl from 7.5 MMBbl in 2022 to 8.3 MMBbl in 2023. The increase was attributable to increased production in thePermian Basin due to the timing of our drilling and completion activities. •NGL production increased 1.0 MMBbl from 6.5 MMBbl in 2022 to 7.5 MMBbl in 2023. The increase was attributable to increased production in thePermian Basin due to the timing of our drilling and completion activities.
•Average realized natural gas price was
•Average realized oil price was
•Average realized NGL price was
•Total capital expenditures were
•Drilled 65 gross wells (39.9 net) with a success rate of 100 percent compared to 54 gross wells (41.4 net) with a success rate of 100 percent for the corresponding period of the prior year.
•Turned in line 74 gross wells (48.2 net) in 2023 compared to 50 gross wells (25.0 net) in the corresponding period of 2022.
•Average rig count during 2023 was approximately 6.0, 3.0 and 1.0 rigs in thePermian Basin ,Marcellus Shale andAnadarko Basin , respectively, compared to an average rig count of approximately 6.0, 2.6 and 2.0 rigs in thePermian Basin ,Marcellus Shale andAnadarko Basin , respectively, during the corresponding period of 2022.
•Increased our annual base dividend from
•Implemented our new share repurchase program and repurchased 11 million shares for$268 million during the three months endedMarch 31, 2023 . We repurchased 8 million shares for$192 million during the three months endedMarch 31, 2022 under our previous share repurchase program. 20 -------------------------------------------------------------------------------- Table of Contents 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 are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, geopolitical, economic and other factors. NYMEX oil and natural gas futures prices have strengthened since the reduction of pandemic-related restrictions and increased OPEC+ cooperation. Improving oil and natural gas futures prices in part reflect market expectations of limitedU.S. supply growth from publicly traded companies as a result of capital investment discipline and a focus on delivering free cash flow returns to stockholders. In addition, natural gas prices have benefited from strong worldwide liquefied natural gas demand, which is, in part, a result of buyers shifting from Russian gas due to theUkraine invasion, sustained higherU.S. exports, lower associated gas growth from oil drilling and improvedU.S. economic activity. These pricing increases have been partially offset by reduced gas consumption due to warmer winter weather in theU.S. andEurope and concerns over potential economic recession, negatively impacting natural gas and NGL prices. Oil price futures have improved (although such future prices are still lower than current spot prices) coinciding with recovering global economic activity, lower supply from major oil producing countries, OPEC+ cooperation and moderating inventory levels. 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 may continue to increase further. While oil and natural gas prices have fallen since their peak in 2022, further geopolitical disruptions in 2023, such as those experienced in 2022, may cause such prices to rapidly rise once again. Although 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 increase significantly 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 targeted at limiting or reducing emissions of greenhouse gases. 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.
Inflation
Certain of our capital expenditures and expenses are affected by general inflation, which rose throughout 2022. While rising inflation is typically offset by the higher prices at which we are able to realize on sales of our commodity production, we nevertheless expect to see inflation impact our cost structure for the remainder of 2023, albeit at a more moderate pace compared to 2022. RecentU.S. Tax Legislation OnAugust 16, 2022 , the Inflation Reduction Act ("IRA") was signed into law pursuant to the budget reconciliation process. The IRA introduced a new 15 percent corporate alternative minimum tax ("CAMT"), effective for tax years beginning afterDecember 31, 2022 , on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding$1 billion over a three-year testing period. The IRA also introduced an excise tax of one percent on the fair market value of certain public company stock repurchases made afterDecember 31, 2022 . Based on the current CAMT guidance available, we will be an "applicable corporation" beginning in 2023, but is not currently expecting to owe any additional tax under the CAMT in 2023.
Outlook
Our 2023 capital program is expected to be approximately$2.0 billion to$2.2 billion . We expect to fund these capital expenditures with our operating cash flow and, if required, cash on hand. We expect to turn-in-line 152 to 165 total net wells in 2023 across our three operating regions. Approximately 49 percent of our drilling and completion capital is expected to be invested in thePermian Basin , 44 percent in theMarcellus Shale and the remaining balance in theAnadarko Basin . 21 -------------------------------------------------------------------------------- Table of Contents In 2022, we drilled 285 gross wells (174.6 net) and turned in line 251 gross wells (148.1 net). For the three months endedMarch 31, 2023 , our capital program focused on thePermian Basin ,Marcellus Shale andAnadarko Basin , where we drilled 39.9 net wells and turned in line 48.2 net wells. Our capital program for the remainder of 2023 will focus on execution of our 2023 plan. We allocate our planned program for capital expenditures based on market conditions, return on capital and free cash flow expectations and availability of services and human resources. We will continue to assess the oil and natural gas price environment and may adjust our capital expenditures 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 maturity 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 non-strategic assets, and private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and there are no "rating triggers" in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. 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.
We plan to continue our practice of entering into hedging agreements to reduce the impact of commodity price volatility on our cash flow from operations.
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, 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. AtMarch 31, 2023 andDecember 31, 2022 , we had a working capital surplus of$796 million and$1.0 billion , respectively. We believe we have adequate liquidity and availability as outlined above to meet our working capital requirements over the next 12 months.
As of
Our revolving credit agreement includes a covenant limiting our borrowing capacity based on our leverage ratio. AtMarch 31, 2023 , we were in compliance with all financial and other covenants applicable to our revolving credit facility and senior notes. Refer to Note 3 of the Notes to the Condensed Consolidated Financial Statements, "Debt and Credit Agreements," for further details regarding our revolving credit agreement. Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and, from time to time, private or public financing based on our monitoring of capital markets and our balance sheet. We also may use a combination of these sources of funds to refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise, but we have no obligation to do so. 22 -------------------------------------------------------------------------------- Table of Contents Cash Flows
Our cash flows from operating activities, investing activities and financing activities were as follows:
Three Months Ended
March 31,
(In millions) 2023 2022
Cash flows provided by operating activities $ 1,494 $ 1,322
Cash flows used in investing activities (479) (269)
Cash flows used in financing activities (715) (642)
Net increase in cash, cash equivalents and restricted cash
$ 411 Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. Commodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and geopolitical, economic and other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. Net cash provided by operating activities for the three months endedMarch 31, 2023 increased by$172 million compared to the same period in 2022. This increase was primarily due to higher cash received on derivative settlements and a larger increase in working capital and other assets and liabilities, partially offset by lower natural gas, oil and NGL revenue and higher operating expenses. The decrease in natural gas, oil and NGL revenue was primarily due to lower realized prices partially offset by slightly higher equivalent production compared to the three months endedMarch 31, 2022 . 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 increased by$210 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 . The increase was primarily due to$213 million of higher capital expenditures due to our increased capital budget for 2023. Financing Activities. Cash flows used in financing activities increased by$73 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 . The increase in cash flows used in financing activities was primarily due to higher common stock repurchases of$84 million during the three months endedMarch 31, 2023 compared to 2022. This increase was partially offset by lower dividend payments of$20 million as a result of a decrease in outstanding shares of common stock due to our share repurchase programs, partially offset by an increase in our base-plus-variable dividend rate from$0.56 for the three months endedMarch 31, 2022 compared to$0.57 for the three months endedMarch 31, 2023 . Capitalization
Information about our capitalization is as follows:
March 31, December 31,
(In millions) 2023 2022
Debt (1) $ 2,176 $ 2,181
Stockholders' equity 12,643 12,659
Total capitalization $ 14,819 $ 14,840
Debt to total capitalization 15 % 15 %
Cash and cash equivalents $ 973 $ 673 ________________________________________________________
(1)There were no borrowings outstanding under our revolving credit agreement as
of
Share repurchases. InFebruary 2023 , our Board of Directors approved a share repurchase program which authorizes the purchase of up to$2.0 billion of our common stock in the open market or in negotiated transactions.
During the three months ended
23
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Dividends. In February 2023 , our Board of Directors approved an increase in the
base quarterly dividend from $0.15 per share to $0.20 per share.
The following table summarizes our dividends on our common stock for each
quarter in 2023 and 2022.
Rate Per Share
Total Dividends
Fixed Variable Total (In millions)
2023
First quarter $ 0.20 $ 0.37 $ 0.57 $ (438)
2022
First quarter $ 0.15 $ 0.41 $ 0.56 $ (455)
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital expenditures with cash
flow provided by operating activities, and, if required, cash on hand and
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:
Three Months Ended
March 31,
(In millions) 2023 2022
Capital expenditures:
Drilling and facilities $ 523 $ 314
Leasehold acquisitions 1 1
Pipeline and gathering 38 8
Other 7 3
569 326
Exploration expenditures(1) 4 6
$ 573 $ 332 ________________________________________________________
(1)There were no exploratory dry hole costs for the three months ended
For the three months endedMarch 31, 2023 , our capital program was focused on thePermian Basin ,Marcellus Shale andAnadarko Basin , where we drilled 39.9 net wells and turned in line 48.2 net wells. We expect our 2023 capital program to be approximately$2.0 billion to$2.2 billion . Refer to "Outlook" 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 "Transportation, Processing and Gathering 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 inthe 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. 24 -------------------------------------------------------------------------------- Table of Contents RESULTS OF OPERATIONS
First Three Months of 2023 and 2022 Compared
Operating Revenues
Three Months Ended March 31, Variance
(In millions) 2023 2022 Amount Percent
Operating Revenues
Natural gas $ 822 $ 1,111 $ (289) (26) %
Oil 615 699 (84) (12) %
NGL 177 245 (68) (28) %
Gain (loss) on derivative instruments 138 (391) 529 135 %
Other 25 15 10 67 %
$ 1,777 $ 1,679 $ 98 6 %
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
we expect to fluctuate due to supply and demand factors, and the availability of
transportation, seasonality and geopolitical, economic and other factors.
Natural Gas Revenues
Three Months Ended March 31, Variance Increase
(Decrease)
2023 2022 Amount Percent (In millions)
Volume variance (Bcf) 248.1 256.4 (8.3) (3) % $ (36)
Price variance ($/Mcf) $ 3.31 $ 4.33 $ (1.02) (23) % (253)
$ (289)
Natural gas revenues decreased $289 million primarily due to lower natural gas
prices and slightly lower production. The lower production is primarily due
lower production in the Marcellus Shale , partially offset by a modest increases
in the Permian and Anadarko Basins production, all of which are due to the
timing our drilling and completion activities.
Oil Revenues
Three Months Ended March 31, Variance Increase
(Decrease)
2023 2022 Amount Percent (In millions)
Volume variance (MMBbl) 8.3 7.5 0.8 11 % $ 75
Price variance ($/Bbl) $ 74.03 $ 93.45 $ (19.42) (21) % (159)
$ (84)
Oil revenues decreased $84 million primarily due to lower oil prices offset by
higher production. The higher production was primarily related to higher Permian
Basin production, which aligned with our 2023 drilling and completion program
for modest production growth.
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NGL Revenues
Three Months Ended March 31, Variance Increase
(Decrease)
2023 2022 Amount Percent (In millions)
Volume variance (MMBbl) 7.5 6.5 1.0 15 % $ 38
Price variance ($/Bbl) $ 23.66 $ 37.87 $ (14.21) (38) % (106)
$ (68)
NGL revenues decreased $68 million primarily due to lower NGL prices offset by
higher production. The higher production was primarily related to higher Permian
Basin production, which aligned with our 2023 drilling and completion program
for modest production growth.
Gain (Loss) 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 (loss) on derivative instruments" for the periods indicated:
Three Months Ended
March 31,
(In millions) 2023 2022Cash received (paid) on settlement of derivative instruments Gas contracts
$ 99 $ (42) Oil contracts 1 (129) Non-cash gain (loss) on derivative instruments Gas contracts 42 (182) Oil contracts (4) (38)$ 138 $ (391)
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 have remained high due to on-going demand for those items, and to a
lesser extent rising inflation and supply chain disruptions, all of which have
affected the cost of our operations throughout 2022. We currently expect these
costs to level off and stabilize during 2023.
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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 March 31, Variance Per BOE
(In millions, except per BOE) 2023 2022 Amount Percent 2023 2022
Operating Expenses
Direct operations $ 134 $ 100 $ 34 34 % $ 2.34 $ 1.76
Transportation, processing and
gathering 236 233 3 1 % 4.13 4.11
Taxes other than income 86 76 10 13 % 1.50 1.34
Exploration 4 6 (2) (33) % 0.07 0.11
Depreciation, depletion and
amortization 369 360 9 3 % 6.45 6.35
General and administrative 76 107 (31) (29) % 1.33 1.89
$ 905 $ 882 $ 23 3 %
Direct Operations
Direct operations generally consists of costs for labor, equipment, maintenance,
saltwater disposal, compression, power, treating and miscellaneous other costs
(collectively, "lease operating expense"). Direct operations also includes 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 March 31, Per BOE
(In millions, except per BOE) 2023 2022 Variance 2023 2022
Direct Operations
Lease operating expense $ 106 $ 82 $ 24 $ 1.85 $ 1.44
Workover expense 28 18 10 0.49 0.32
$ 134 $ 100 $ 34 $ 2.34 $ 1.76 Lease operating expense increased primarily due to general higher costs of equipment and field services, along with increased labor costs.
Workover expense increased$10 million primarily due to an increase in workover activities related to maintenance project activities in thePermian Basin andMarcellus Shale resulting in an increase of$5 million and$4 million , respectively, compared to 2022 activities.
Transportation, Processing and Gathering
Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression and 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.
Transportation, processing and gathering costs increased
Taxes Other Than Income
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.
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The following table presents taxes other than income for the periods indicated:
Three Months Ended March 31,
(In millions) 2023 2022 VarianceTaxes Other than Income Production $ 60$ 63 $ (3) Drilling impact fees 9 7 2 Ad valorem 16 6 10 Other 1 - 1 $ 86$ 76 $ 10 Production taxes as a percentage of production revenue 3.7 %
3.1 %
Taxes other than income increased$10 million . Production taxes represented the majority of our taxes other than income, which decreased primarily due to lower oil and NGL revenues. Drilling impact fees increased primarily due to the timing of wells drilled in theMarcellus Shale . Ad valorem taxes increased primarily due to higher anticipated appraisal values based on 2022 results of operations in thePermian Basin , which is expected to impact 2023 property assessments.
Depreciation, Depletion and Amortization ("DD&A")
DD&A expense consisted of the following for the periods indicated:
Three Months Ended March 31, Per BOE
(In millions, except per BOE) 2023 2022 Variance 2023 2022
DD&A Expense
Depletion $ 337 $ 339 $ (2) $ 5.89 $ 5.98
Depreciation 17 19 (2) 0.30 0.33
Amortization of unproved properties 12 - 12 0.21 -
Accretion of ARO 3 2 1 0.05 0.04
$ 369 $ 360 $ 9 $ 6.45 $ 6.35
Depletion of our producing properties is computed on a field basis using the
unit-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 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. An overall lower
depletion rate, partially offset by higher production, contributed to the $2
million decrease in depletion expense. The decrease in the depletion rate was
due to a decrease in the depletion rate in the Permian Basin due to increased
reserves at December 31, 2022 , partially offset by an increase in the depletion
rate in the Marcellus Shale due to downward reserve revisions in September 2022 .
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. Amortization of unproved properties increased$12 million due to the amortization of our unproved properties based on our expectations of converting leases acquired in the merger to held by production. 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. 28 -------------------------------------------------------------------------------- Table of Contents 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 March 31,
(In millions) 2023 2022 Variance
G&A Expense
General and administrative expense $ 53 $ 53 $ -
Stock-based compensation expense 16 23 (7)
Merger-related expense 7 31 (24)
$ 76 $ 107 $ (31) G&A expense, excluding stock-based compensation and merger-related expenses, did not have individually significant fluctuations.
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 the accelerated vesting of employee performance shares in 2022 and a decrease in the Company's share price as ofMarch 31, 2023 compared toMarch 31, 2022 . Merger-related expenses decreased$24 million primarily due to$17 million of lower employee-related severance and termination benefits associated with the expected termination of certain employees, which is being accrued over the expected transition period and a decrease of$7 million of transaction-related costs associated with the Merger.
Interest Expense
The table below reflects our interest expense for the periods indicated:
Three Months Ended March 31,
(In millions) 2023 2022 Variance
Interest Expense
Interest expense $ 20 $ 30 $ (10)
Debt premium amortization (5) (11) 6
Debt financing costs 1 1 -
Other 1 1 -
$ 17 $ 21 $ (4)
Interest expense decreased $10 million primarily due to the repayment of our
6.51% and 5.58% weighted-average private placement senior notes in August 2022
and the redemption of $750 million of the 4.375% senior notes in September and
October 2022 .
Debt premium amortization decreased
Interest Income
Interest income increased
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Income Tax Expense
Three Months Ended March 31,
(In millions) 2023 2022 Variance
Income Tax Expense
Current tax expense $ 172 $ 134 $ 38
Deferred tax expense 23 36 (13)
$ 195 $ 170 $ 25
Combined federal and state effective income
tax rate 22.4 % 22.0 %
Income tax expense increased$25 million due to higher pre-tax income as well as a slightly higher effective tax rate. The effective tax rate increased for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 due to differences in the non-recurring discrete items recorded during the three months endedMarch 31, 2023 and 2022.
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, the anticipated effects of, and certain other matters related to, the Merger involvingCimarex Energy Co. ("Cimarex"), strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in or incorporated by reference into this report, are forward-looking statements. 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 impact of public health crises, including pandemics (such as the coronavirus pandemic) and epidemics and any related company or governmental policies of actions, the risk that our and Cimarex's businesses will not be integrated successfully, the risk that the cost savings and any other synergies from the Merger involving Cimarex may not be fully realized or may take longer to realize than expected, 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, including as a result of instability in the banking sector, pandemics and geopolitical disruptions such as the war inUkraine , results of future drilling and marketing activities, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our otherSecurities and Exchange Commission ("SEC") filings. Refer to "Risk Factors" in Item 1A of Part I of our 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 inSEC filings, press releases and public conference calls. Based on guidance from theSEC , 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.
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