SM ENERGY COMPANY The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.
Overview of the Company
General Overview
Our strategy is to be a premier operator of top-tier oil and gas assets. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our purpose is to make people's lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision is to sustainably grow value for all of our stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our near-term goals include returning value to stockholders through our Stock Repurchase Program and fixed dividend payments, which increased during 2022. Our asset portfolio is comprised of high-quality assets in theMidland Basin ofWest Texas and in theMaverick Basin ofSouth Texas that are capable of generating strong returns in the current macroeconomic environment, and present resilience to commodity price risk. We remain focused on maximizing returns and increasing the value of our top-tier assets through continued development and optimization of ourMidland Basin assets and through continued delineation of the Austin Chalk formation inSouth Texas . We believe that our high-quality asset base provides for a sustainable and repeatable approach to prioritizing operational execution, maintaining strong cash flows, returning capital to stockholders, continuing to improve leverage metrics, and maintaining strong financial flexibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas.The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company's ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based metrics that include key financial, operational, and environmental, health, and safety measures. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2023 annual meeting of stockholders to be filed within 120 days fromDecember 31, 2022 , for additional discussion. Global commodity and financial markets remain subject to high levels of macroeconomic uncertainty and volatility as a result of inflation, the ongoing conflict betweenRussia andUkraine and associated economic and trade sanctions onRussia , and the Pandemic. These events have been drivers of volatile commodity prices and contributed to increased service provider costs, instances of supply chain disruptions, and a rise in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. Future impacts of these and other events on commodity and financial markets are inherently unpredictable. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We are focused on returning capital to shareholders through increasing returns and cash flow generation.
2022 Financial and Operational Highlights
During 2022, we accomplished the near-term goals established at the beginning of the year to improve our leverage metrics by reducing the principal balance of our outstanding debt through cash flow generation and increasing the value of our capital project inventory. For the year endedDecember 31, 2022 , net cash provided by operating activities exceeded net cash used in investing activities by$806.1 million , and we reduced the principal balance of our total outstanding long-term debt by$551.4 million by redeeming the remaining outstanding aggregate principal balance of our 2024 Senior Notes and our 2025 Senior Secured Notes. Our Board of Directors authorized the Stock Repurchase Program and increased our fixed dividend to$0.60 per share annually, to be paid in quarterly increments of$0.15 per share, both of which align with our goal to implement a sustainable and repeatable capital return program that creates long-term value for our stockholders. During the year endedDecember 31, 2022 , we repurchased and subsequently retired 1,365,255 shares of our common stock at a cost of$57.2 million . Please refer to Note 3 - Equity and Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions. Financial and Operational Results. Average net daily equivalent production for the year endedDecember 31, 2022 , increased three percent to 145.1 MBOE, compared with 140.7 MBOE for 2021. The total increase consisted of a 37 percent increase from ourSouth Texas assets, which outpaced a 14 percent decrease from ourMidland Basin assets, as a result of increased capital allocation to ourAustin Chalk assets. Realized prices for oil, gas, and NGLs increased 40 percent, 29 percent, and six percent, respectively, for the year endedDecember 31, 2022 , compared with 2021. As a result of increased realized prices, oil, gas, and NGL production revenue increased 29 percent to$3.3 billion for the year endedDecember 31, 2022 , compared with$2.6 billion for 2021. We recorded a net derivative loss of$374.0 million for the year endedDecember 31, 2022 , compared with a$901.7 million net derivative loss for 2021. 39 -------------------------------------------------------------------------------- These amounts include derivative settlement losses of$710.7 million and$749.0 million for the years endedDecember 31, 2022 , and 2021, respectively. Operational activities during the year endedDecember 31, 2022 , resulted in the following financial and operational results:
•Net cash provided by operating activities of
•Net income of
•Adjusted EBITDAX, a non-GAAP financial measure, for the year endedDecember 31, 2022 , of$1.9 billion , compared with$1.2 billion for 2021. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities. •Total estimated proved reserves as ofDecember 31, 2022 , increased nine percent fromDecember 31, 2021 , to 537.4 MMBOE, of which, 56 percent were liquids (oil and NGLs) and 59 percent were proved developed reserves. The increase to total estimated proved reserves was primarily driven by 103.2 MMBOE of infill reserves, partially offset by 53.0 MMBOE of production during 2022 and the removal of 19.9 MMBOE of proved undeveloped reserves reclassified to unproved reserves categories as a result of development plan optimization. Our proved reserve life index increased to 10.1 years as ofDecember 31, 2022 , compared with 9.6 years as ofDecember 31, 2021 . Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was$10.0 billion as ofDecember 31, 2022 , compared with$7.0 billion as ofDecember 31, 2021 , which was an increase of 43 percent year-over-year. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion. Operational Activities. During 2022, we continued to experience strong well performance in the RockStar area of ourMidland Basin position due to successful operational execution, enhanced drilling and completion designs, and our focus on capital efficiency. OurSouth Texas program benefited from continued successful delineation and development of the Austin Chalk formation in addition to the sustained strong performance of ourEagle Ford shale wells. Our continued success in both ourMidland Basin andSouth Texas programs is attributable to our top-tier assets and our continued commitment to geoscience, technology, and innovation. OurMidland Basin program averaged three drilling rigs and one completion crew during 2022. We drilled 63 gross (50 net) wells and completed 44 gross (36 net) wells during 2022, and net equivalent production decreased year-over-year by 14 percent to 29.7 MMBOE. Costs incurred during 2022 totaled$476.2 million , or 50 percent of our total 2022 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in theMidland Basin continue to focus primarily on developing the Spraberry and Wolfcamp formations. OurSouth Texas program averaged two drilling rigs and one completion crew during 2022. We drilled 41 gross (40 net) wells and completed 43 gross (43 net) wells during 2022, and net equivalent production increased year-over-year by 37 percent to 23.2 MMBOE. Costs incurred during 2022 totaled$431.0 million , or 45 percent of our total 2022 costs incurred. Drilling and completion activities inSouth Texas during 2022 were primarily focused on developing the Austin Chalk formation. The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the year endedDecember 31, 2022 : Midland Basin South Texas Total Gross Net Gross Net Gross Net Wells drilled but not completed at December 31, 2021 (1) 30 27 32 32 62 59 Wells drilled (2) 63 50 41 40 104 90 Wells completed (2) (44) (36) (43) (43) (87) (79) Other (3) - - (1) (1) (1) (1) Wells drilled but not completed at December 31, 2022 (4)(5) 49 40 29 28 78 69
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(1) TheSouth Texas drilled but not completed well count as ofDecember 31, 2021 , included 11 gross (11 net) wells that were not included in our five-year development plan as ofDecember 31, 2021 , 10 of which were in the Eagle Ford shale. (2) Wells drilled and completed during the year endedDecember 31, 2022 , exclude one drilled and completed well that was subsequently abandoned, outside of our core areas of operation. (3) In 2022, we drilled a science well to study and monitorAustin Chalk reservoir activity during and after development. We do not intend to complete this well. (4) TheSouth Texas drilled but not completed well count as ofDecember 31, 2022 , includes nine gross (nine net) wells that are not included in our five-year development plan, eight of which are in the Eagle Ford shale. (5) Amounts may not calculate due to rounding. 40 -------------------------------------------------------------------------------- Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows: For the Year Ended December 31, 2022 (in millions) Development costs $ 810.5 Exploration costs 147.0 Acquisitions Proved properties - Unproved properties 4.2 Total, including asset retirement obligations (1) $ 961.7
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(1) Please refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year endedDecember 31, 2022 : Midland Basin South Texas Total Net production volumes: Oil (MMBbl) 19.1 4.9 24.0 Gas (Bcf) 63.5 62.5 125.9 NGLs (MMBbl) - 8.0 8.0 Equivalent (MMBOE) 29.7 23.2 53.0 Average net daily equivalent (MBOE per day) 81.4 63.7 145.1 Relative percentage 56 % 44 % 100 %
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Note: Amounts may not calculate due to rounding.
Net equivalent production increased three percent for the year endedDecember 31, 2022 , compared with 2021, comprised of a 37 percent increase from ourSouth Texas assets, partially offset by a 14 percent decrease from ourMidland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 below for additional discussion on production.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly
affected by the prices we receive for our oil, gas, and NGL production, which
can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices
below, the disclosed price represents the average price for the respective
period, before the effect of derivative settlements. While quoted NYMEX oil and
gas and OPIS NGL prices are generally used as a basis for comparison within our
industry, the prices we receive are affected by quality, energy content,
location and transportation differentials, and contracted pricing benchmarks for
these products.
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The following table summarizes commodity price data, as well as the effect of
derivative settlements, for the years ended December 31, 2022 , 2021, and 2020:
For the Years Ended December 31,
2022 2021 2020
Oil (per Bbl):
Average NYMEX contract monthly price $ 94.23 $ 67.92 $ 39.40
Realized price $ 94.67 $ 67.72 $ 37.08
Effect of oil derivative settlements $ (21.46) $
(18.73)
Gas:
Average NYMEX monthly settle price (per MMBtu)$ 6.64 $ 3.84 $ 2.08 Realized price (per Mcf)$ 6.28 $ 4.85 $ 1.80 Effect of gas derivative settlements (per Mcf)$ (1.36) $ (1.41) $ 0.11 NGLs (per Bbl): Average OPIS price (1)$ 43.48 $ 36.65 $ 17.96 Realized price$ 35.66 $ 33.67 $ 13.96 Effect of NGL derivative settlements$ (3.06) $
(13.68)
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(1) Average OPIS prices per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix. Commodity prices increased in 2022 compared with both 2021 and 2020. However, given the uncertainty surrounding the ongoing conflict betweenRussia andUkraine , the economic and trade sanctions that certain countries have imposed onRussia , production output from OPEC+, and the potential impacts of these issues on global commodity and financial markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future. We cannot reasonably predict the timing or likelihood of any future commodity prices fluctuations that could be caused by further inflation, supply chain disruptions, a continued rise in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength ofthe United States dollar compared to other currencies. Our realized prices at local sales points may also be affected by infrastructure capacity in the areas of our operations and beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX
Henry Hub gas, and OPIS NGLs as of
As of February 9, 2023 As of December 31, 2022
NYMEX WTI oil (per Bbl) $ 77.05 $ 79.47
NYMEX Henry Hub gas (per MMBtu) $ 3.19 $ 4.26
OPIS NGLs (per Bbl) $ 31.09 $ 29.85
We use financial derivative instruments as part of our financial risk management
program. We have a financial risk management policy governing our use of
derivatives, and decisions regarding entering into commodity derivative
contracts are overseen by a financial risk management committee consisting of
certain senior executive officers and finance personnel. We make decisions about
the amount of our expected production that we cover by derivatives based on the
amount of debt on our balance sheet, the level of capital commitments and
long-term obligations we have in place, and the terms and futures prices that
are made available by our approved counterparties. With our current commodity
derivative contracts, we believe we have partially reduced our exposure to
volatility in commodity prices and basis differentials in the near term. Our use
of costless collars for a portion of our derivatives allows us to participate in
some of the upward movements in oil and gas prices while also setting a price
floor below which we are insulated from further price decreases. Please refer to
Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report and
to Commodity Price Risk in Overview of Liquidity and Capital Resources below for
additional information regarding our oil, gas, and NGL derivatives.
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--------------------------------------------------------------------------------Outlook
Our total 2023 capital program, which we expect to fund with cash flows from operations, is expected to be approximately$1.1 billion . We plan to focus our 2023 capital program on highly economic oil development projects in both ourMidland Basin andSouth Texas assets. We expect to repurchase additional shares of our outstanding common stock through our Stock Repurchase Program during 2023, under which$442.8 million remained available for repurchases as ofDecember 31, 2022 .
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months endedDecember 31, 2022 , and the preceding three quarters: For the Three Months Ended December 31, September 30, June 30, March 31, 2022 2022 2022 2022 (in millions) Production (MMBOE) 13.1 12.7 13.3 13.8
Oil, gas, and NGL production revenue
$ 990.4 $ 858.7 Oil, gas, and NGL production expense$ 150.7 $ 160.0 $ 165.6 $ 144.7 Depletion, depreciation, amortization, and asset retirement obligation liability accretion$ 143.6 $ 145.9 $ 154.8 $ 159.5 Exploration$ 10.8 $ 14.2$ 20.9 $ 9.0 General and administrative$ 32.8 $ 28.4$ 28.3 $ 25.0 Net income$ 258.5 $ 481.2 $ 323.5 $ 48.8
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Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
For the Three Months Ended
December 31, September 30, June 30, March 31,
2022 2022 2022 2022
Average net daily equivalent production
(MBOE per day) 142.9 137.8 146.6 153.3
Lease operating expense (per BOE) $ 5.20 $ 5.64 $ 5.11 $ 4.25
Transportation costs (per BOE) $ 2.86 $ 2.87 $ 2.87 $ 2.74
Production taxes as a percent of oil,
gas, and NGL production revenue 4.8 % 4.9 % 5.1 % 4.7 %
Ad valorem tax expense (per BOE) $ 0.97 $ 0.93 $ 0.69 $ 0.58
Depletion, depreciation, amortization,
and asset retirement obligation
liability accretion (per BOE) $ 10.93 $ 11.50 $ 11.60 $ 11.56
General and administrative (per BOE) $ 2.50 $ 2.24 ____________________________________________
Note: Amounts may not calculate due to rounding.
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--------------------------------------------------------------------------------Overview of Selected Production and Financial Information, Including Trends
For the Years Ended Amount Change Between Percent Change Between
December 31,
2022 2021 2020 2022/2021 2021/2020 2022/2021 2021/2020
Net production volumes:
(1)
Oil (MMBbl) 24.0 27.9 23.0 (4.0) 4.9 (14) % 21 %
Gas (Bcf) 125.9 108.4 103.9 17.6 4.5 16 % 4 %
NGLs (MMBbl) 8.0 5.4 6.1 2.6 (0.7) 49 % (12) %
Equivalent (MMBOE) 53.0 51.4 46.4 1.6 4.9 3 % 11 %
Average net daily
production: (1)
Oil (MBbl per day) 65.7 76.5 62.9 (10.8) 13.6 (14) % 22 %
Gas (MMcf per day) 345.0 296.9 283.9 48.1 13.0 16 % 5 %
NGLs (MBbl per day) 21.9 14.7 16.7 7.2 (2.0) 49 % (12) %
Equivalent (MBOE per
day) 145.1 140.7 126.9 4.4 13.9 3 % 11 %
Oil, gas, and NGL production revenue (in millions):
(1)
Oil production revenue $ 2,270.1 $ 1,891.8 $ 853.6 $ 378.2 $ 1,038.3 20 % 122 %
Gas production revenue 790.9 525.5 187.5 265.4 338.0 51 % 180 %
NGL production revenue 285.0 180.6 85.2 104.3 95.4 58 % 112 %
Total oil, gas, and NGL
production revenue
$ 1,471.7 29 % 131 % Oil, gas, and NGL production expense (in millions): (1) Lease operating expense$ 266.5 $ 225.5 $ 184.2 $ 41.0 $ 41.2 18 % 22 % Transportation costs 150.0 139.4 142.0 10.6 (2.6) 8 % (2) % Production taxes 162.6 121.1 46.1 41.5 75.0 34 % 163 % Ad valorem tax expense 41.7 19.4 18.9 22.3 0.5 115 % 3 % Total oil, gas, and NGL production expense$ 620.9 $ 505.4 $ 391.2 $ 115.5 $ 114.2 23 % 29 % Realized price: Oil (per Bbl)$ 94.67 $ 67.72 $ 37.08 $ 26.95 $ 30.64 40 % 83 % Gas (per Mcf)$ 6.28 $ 4.85 $ 1.80 $ 1.43 $ 3.05 29 % 169 % NGLs (per Bbl)$ 35.66 $ 33.67 $ 13.96 $ 1.99 $ 19.71 6 % 141 % Per BOE$ 63.18 $ 50.58 $ 24.26 $ 12.60 $ 26.32 25 % 108 % Per BOE data: (1) Oil, gas, and NGL production expense: Lease operating expense$ 5.03 $ 4.39 $ 3.97 $ 0.64 $ 0.42 15 % 11 % Transportation costs 2.83 2.71 3.06 0.12 (0.35) 4 % (11) % Production taxes 3.07 2.36 0.99 0.71 1.37 30 % 138 % Ad valorem tax expense 0.79 0.38 0.41 0.41 (0.03) 108 % (7) % Total oil, gas, and NGL production expense$ 11.72 $ 9.84 $ 8.43 $ 1.88 $ 1.41 19 % 17 % Depletion, depreciation, amortization, and asset retirement obligation liability accretion$ 11.40 $ 15.08 $ 16.91 $ (3.68) $ (1.83) (24) % (11) % General and administrative$ 2.16 $ 2.18 $ 2.14 $ (0.02) $ 0.04 (1) % 2 % Derivative settlement gain (loss) (2)$ (13.42) $ (14.58) $ 7.57 $ 1.16 $ (22.15) 8 % (293) % Earnings per share information (in thousands, except per share data): (3) Basic weighted-average common shares outstanding 122,351 119,043 113,730 3,308 5,313 3 % 5 % Diluted weighted-average common shares outstanding 124,084 123,690 113,730 394 9,960 - % 9 % Basic net income (loss) per common share$ 9.09 $ 0.30 $ (6.72) $ 8.79 $ 7.02 2,930 % 104 % Diluted net income (loss) per common share$ 8.96 $ 0.29 $ (6.72) $ 8.67 $ 7.01 2,990 % 104 % 44
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(1) Amounts and percentage changes may not calculate due to rounding. (2) Derivative settlements for the years endedDecember 31, 2022 , 2021, and 2020, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations ("accompanying statements of operations"). (3) Please refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report for additional discussion. Average net daily equivalent production for the year endedDecember 31, 2022 , increased three percent compared with 2021, as a result of a 37 percent increase in average net daily equivalent production from ourSouth Texas assets outpacing a 14 percent decrease in average net daily equivalent production from ourMidland Basin assets, as a result of increased capital allocation to ourAustin Chalk assets. In 2023, we expect total production volumes to remain relatively flat compared with 2022, and we expect a slight decrease in oil as a percentage of total production. Please refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 below for additional discussion.
We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.
Our realized price on a per BOE basis increased$12.60 for the year endedDecember 31, 2022 , compared with 2021, primarily as a result of increased benchmark commodity prices. The loss on settlement of our commodity derivative contracts decreased$1.16 per BOE resulting from a lower percentage of production volumes covered by commodity derivative contracts that settled during the year endedDecember 31, 2022 , compared with 2021. LOE on a per BOE basis increased 15 percent for the year endedDecember 31, 2022 , compared with 2021, primarily driven by increases in workover activity, and service provider costs that were impacted by inflation. For 2023, we expect LOE on a per BOE basis to increase, compared with 2022, primarily as a result of anticipated increases in service provider costs attributable to inflation, and increased workover activity, which we expect to be partially offset by increasing activity in the Austin Chalk, where operating costs are lower than in theMidland Basin . We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, inflation, and industry activity, all of which impact total LOE. Transportation costs on a per BOE basis increased four percent for the year endedDecember 31, 2022 , compared with 2021. This increase was the result of a 37 percent increase in net daily equivalent production volumes from ourSouth Texas assets which was partially offset by transportation contract cost reductions. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from ourSouth Texas assets, where we incur a majority of our transportation costs. For 2023, we expect transportation costs on a per BOE basis to decrease compared with 2022 as a result of transportation cost reductions in the second half of 2023 resulting from the expiration of a long-term contract inSouth Texas . Production tax expense on a per BOE basis for the year endedDecember 31, 2022 , increased 30 percent compared with 2021, primarily driven by increases in realized prices. Our overall production tax rate was 4.9 percent and 4.7 percent for the years endedDecember 31, 2022 , and 2021, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize. Ad valorem tax expense on a per BOE basis increased 108 percent for the year endedDecember 31, 2022 , compared with 2021, as a result of increases to the assessed values of our producing properties, driven by increases in commodity prices. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes. Depletion, depreciation, amortization, and asset retirement obligation liability accretion ("DD&A") expense on a per BOE basis decreased 24 percent for the year endedDecember 31, 2022 , compared with 2021, as a result of increased estimated proved reserves at the end of 2021 and during 2022, and increased activity in ourAustin Chalk program, which has lower DD&A rates compared to ourMidland Basin assets. We expect DD&A expense per BOE and on an absolute basis to increase slightly in 2023, compared with 2022, primarily as a result of inflation, partially offset by increased activity in ourAustin Chalk program. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, divestiture activity, and carrying cost funding and sharing arrangements with third parties. General and administrative ("G&A") expense on a per BOE basis remained relatively flat for the year endedDecember 31, 2022 , compared with 2021. For 2023, we expect G&A expense per BOE and on an absolute basis to increase compared with 2022, primarily as a result of expected increases in compensation expense.
Please refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 for additional discussion of operating expenses.
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--------------------------------------------------------------------------------Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020
Please refer to Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 in Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2021 Annual Report on Form 10-K, filed with theSEC onFebruary 25, 2022 , for a detailed discussion of certain comparisons of our financial results and trends for the year endedDecember 31, 2021 , compared with the year endedDecember 31, 2020 .
Average net daily equivalent production, production revenue, and production expense
The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years endedDecember 31, 2022 , and 2021: Net Equivalent Production Production Revenue Production Expense Increase (Decrease) Increase Increase (MBOE per day) (in millions) (in millions) Midland Basin (13.0) $ 222.0 $ 55.5 South Texas 17.3 526.0 60.0 Total 4.4 $ 748.0 $ 115.5
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Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes for the year endedDecember 31, 2022 , increased three percent compared with 2021, comprised of a 37 percent increase from ourSouth Texas assets, partially offset by a 14 percent decrease from ourMidland Basin assets. Realized prices for oil, gas, and NGLs increased 40 percent, 29 percent, and six percent, respectively, for the year endedDecember 31, 2022 , compared with 2021. As a result of increased production and pricing, production revenue for oil, gas, and NGLs increased 29 percent for the year endedDecember 31, 2022 , compared with 2021. Total production expense for the year endedDecember 31, 2022 , increased 23 percent, compared with 2021, primarily as a result of increased production taxes and LOE. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years endedDecember 31, 2021 , and 2020: Net Equivalent Production Production Revenue Production Expense Increase (Decrease) Increase Increase (MBOE per day) (in millions) (in millions) Midland Basin 14.9 $ 1,148.8 $ 95.0 South Texas (1.0) 322.9 19.2 Total 13.9 $ 1,471.7 $ 114.2
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Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes for the year endedDecember 31, 2021 , increased 11 percent compared with 2020, comprised of a 19 percent increase from ourMidland Basin assets, partially offset by a two percent decrease from ourSouth Texas assets. Realized prices for oil, gas, and NGLs increased 83 percent, 169 percent, and 141 percent, respectively, for the year endedDecember 31, 2021 , compared with 2020. As a result of increased production and pricing, production revenue for oil, gas, and NGLs increased 131 percent for the year endedDecember 31, 2021 , compared with 2020. Total production expense for the year endedDecember 31, 2021 , increased 29 percent compared with 2020, primarily as a result of increased production taxes and LOE.
Please refer to Overview of Selected Production and Financial Information, Including Trends for additional discussion, including discussion of trends on a per BOE basis.
Depletion, depreciation, amortization, and asset retirement obligation liability
accretion
For the Years Ended December 31,
2022 2021 2020
(in millions)
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion
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DD&A expense for the year ended December 31, 2022 , decreased 22 percent compared
with 2021, primarily as a result of increased estimated proved reserves at the
end of 2021 and during 2022, and increased activity in our Austin Chalk program,
which has lower DD&A rates compared to our Midland Basin assets. DD&A expense
for the year ended December 31, 2021 , remained flat compared with 2020. Please
refer to Overview of Selected Production and Financial Information, Including
Trends above for discussion of DD&A expense on a per BOE basis.
Exploration
For the Years Ended December 31,
2022 2021 2020
(in millions)
Geological, geophysical, and other expenses $ 24.7 $ 7.0 $ 11.6
Overhead 30.2 32.3 29.4
Total $ 54.9 $ 39.3 $ 41.0 __________________________________________
Note: Prior periods have been adjusted to conform to the current period presentation.
Exploration expense increased 40 percent for the year endedDecember 31, 2022 , compared with 2021, primarily as a result of unsuccessful exploration activity related to one drilled and completed well that was subsequently abandoned outside of our core areas of operation. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead. Impairment For the Years Ended December 31, 2022 2021 2020 (in millions) Abandonment and impairment of unproved properties$ 7.5 $ 35.0 $ 59.3 Impairment of proved oil and gas properties and related support equipment - - 956.7 Total$ 7.5 $ 35.0 $ 1,016.0 Unproved property abandonments and impairments recorded during the years endedDecember 31, 2022 , 2021, and 2020, related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks. Impairment expense decreased 79 percent for the year endedDecember 31, 2022 , compared with 2021, as a result of fewer actual and anticipated lease expirations and title defects. During the year endedDecember 31, 2020 , we recorded impairment expense related to ourSouth Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments. Reserve estimates and related impairments of proved and unproved properties are difficult to predict in a volatile price environment. If commodity prices for the products we produce decline as a result of supply and demand fundamentals associated with geopolitical or macroeconomic events, we may experience additional proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as ofFebruary 9, 2023 , we do not expect any material oil and gas property impairments in the first quarter of 2023 resulting from commodity price impacts.
Please refer to Critical Accounting Estimates below and Note 8 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion.
47
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General and administrative
For the Years Ended December 31,
2022 2021 2020
(in millions)
General and administrative $ 114.6 $ 111.9 $ 99.2
G&A expense remained flat for the year ended December 31, 2022 , compared with
2021, and increased 13 percent for the year ended December 31, 2021 , compared
with 2020, primarily as a result of increased compensation expense. Please refer
to Overview of Selected Production and Financial Information, Including Trends
above for discussion of G&A expense.
Net derivative (gain) loss
For the Years Ended December 31,
2022 2021 2020
(in millions)
Net derivative (gain) loss $ 374.0 $ 901.7 $ (161.6)
Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. The net derivative losses for the years endedDecember 31, 2022 , and 2021, resulted from increases in benchmark commodity prices during those years. The net derivative gain for the year endedDecember 31, 2020 , resulted from decreases in benchmark commodity prices during 2020. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Other operating expense, net
For the Years Ended December 31,
2022 2021 2020
(in millions)
Other operating expense, net $ 3.5 $ 46.1
Other operating expense, net, recorded in 2021 and 2020, primarily consisted of
legal settlements.
Interest expense
For the Years Ended December 31,
2022 2021 2020
(in millions)
Interest expense $ (120.3) $ (160.4) $ (163.9)
Interest expense decreased 25 percent for the year ended December 31, 2022 ,
compared with 2021, as a result of the reduction in the aggregate principal
amount of our Senior Notes through various transactions in 2022 and 2021. Total
interest expense is impacted by, and can vary based on, the timing and amount of
borrowings under our revolving credit facility. Please refer to Overview of
Liquidity and Capital Resources below, and to Note 5 - Long-Term Debt in Part
II, Item 8 of this report for additional discussion, including the definition of
Senior Notes.
Net gain (loss) on extinguishment of debt
For the Years Ended December 31,
2022 2021 2020
(in millions)
Net gain (loss) on extinguishment of debt $ (67.6)
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The redemption of our 2025 Senior Secured Notes during 2022 resulted in a net
loss on extinguishment of debt of $67.2 million , which included $33.5 million of
premium paid, $26.3 million of accelerated expense recognition of the
unamortized debt discount, and $7.4 million of accelerated expense recognition
of the unamortized deferred financing costs.
The Exchange Offers executed during 2020 resulted in a net gain on
extinguishment of debt of $227.3 million , which was primarily comprised of the
gain on the partial principal redemption of Old Notes and the debt discount
associated with the issuance of the 2025 Senior Secured Notes. Additionally,
during the year ended December 31, 2020 , we repurchased certain of our 2022
Senior Notes and 2024 Senior Notes in open market transactions, resulting in a
net gain on extinguishment of debt of $52.8 million .
Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for
additional discussion, including the definitions of Exchange Offers, Old Notes,
2025 Senior Secured Notes, 2022 Senior Notes, and 2024 Senior Notes.
Income tax (expense) benefit
For the Years Ended December 31,
2022 2021 2020
(in millions, except tax rate)
Income tax (expense) benefit $ (283.8) $ (9.9) $ 192.1
Effective tax rate 20.3 % 21.5 % 20.1 %
The decrease in the effective tax rate for the year ended December 31, 2022 ,
compared with 2021, primarily resulted from the release of the valuation
allowance recorded against the derivative deferred tax asset recognized in prior
periods. As a result of the increase in income before income taxes for the year
ended December 31, 2022 , compared with 2021, the Company's permanent items,
including excess tax benefits from stock-based compensation and limits on
expensing of certain individual's compensation, had less of an impact on the
effective tax rate for the year ended December 31, 2022 , compared with 2021.
The increase in the effective tax rate for the year ended December 31, 2021 ,
compared with 2020, was primarily due to the differing effects of permanent
items on income before income taxes for the year ended December 31, 2021 ,
compared to a loss before income taxes in 2020. During 2021, an additional
valuation allowance recorded against tax effected net derivative liabilities
partially offset by an excess tax benefit from stock-based compensation awards
and other deferred tax adjustments, resulted in an increase in the tax rate
year-over-year.
During 2022, we made federal estimated tax payments of $10.0 million . During the
fourth quarter of 2022, we commissioned a multi-year research and development
("R&D") credit study which is expected to be completed in late 2023. We expect
that this study will result in a favorable impact to our effective tax rate when
the results are recorded.
Changes in federal income tax laws or enactment of proposed legislation to
increase the corporate tax rate and eliminate or reduce certain oil and gas
industry deductions could have a material impact on our effective tax rate and
current tax expense. Effective for tax years beginning after December 31, 2022 ,
the IRA creates a 15 percent corporate alternative minimum tax ("CAMT") on
average annual adjusted financial statement income exceeding $1.0 billion over
any three-year period. The CAMT is currently not expected to have a material
effect on our consolidated financial statements in future periods.
Please refer to Overview of Liquidity and Capital Resources and Critical Accounting Estimates below as well as Note 4 - Income Taxes in Part II, Item 8 of this report for further discussion.
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
Sources of Cash
We expect our 2023 capital expenditure and return of capital programs to be
funded by cash flows from operations. Although we expect cash flows from
operations to be sufficient to fund our 2023 programs, we may also use
borrowings under our revolving credit facility or raise funds through new debt
or equity offerings or from other sources of financing. If we raise additional
funds through the issuance of equity or convertible debt securities, the
percentage ownership of our current stockholders could be diluted, and these
newly issued securities may have rights, preferences, or privileges senior to
those of existing stockholders and bondholders. Additionally, we may enter into
carrying cost and sharing arrangements with third parties for certain
exploration or development programs. All of our sources of liquidity can be
affected by the general conditions of the broader economy, force majeure events,
49
--------------------------------------------------------------------------------fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.
Our credit ratings impact the availability of and cost for us to borrow additional funds. Three major credit rating agencies upgraded our credit ratings during 2022, reflecting our top-tier assets and operational performance, our priority of improving our leverage metrics, our ability to consistently generate cash flows and our decision to use a portion of the proceeds to reduce total debt, our strong liquidity profile, and our use of financial derivative instruments as part of our financial risk management program. We have no control over the market prices for oil, gas, and NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of$3.0 billion , a borrowing base of$2.5 billion , and aggregate lender commitments totaling$1.25 billion . The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next scheduled borrowing base redetermination date isApril 1, 2023 . No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as ofDecember 31, 2022 , and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as ofFebruary 9, 2023 ,December 31, 2022 , andDecember 31, 2021 . We had no revolving credit facility borrowings during the year endedDecember 31, 2022 . Our daily weighted-average revolving credit facility debt balance was$106.0 million for the year endedDecember 31, 2021 . Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, our capital expenditures, including acquisitions, and other financing activities, all impact the amount we borrow under our revolving credit facility.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and for the periods during which they were outstanding, the non-cash amortization of the discounts related to the 2021 Senior Secured Convertible Notes and 2025 Senior Secured Notes, each as defined in Note 5 - Long-Term Debt in Part II, Item 8 of this report. Our weighted-average borrowing rate includes paid and accrued interest only. The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years endedDecember 31, 2022 , 2021, and 2020: For the Years Ended December 31, 2022 2021 2020 Weighted-average interest rate 7.6 % 7.7 % 7.0 % Weighted-average borrowing rate 6.8 % 6.8
% 6.1 %
Our weighted-average interest rate remained flat for the year endedDecember 31, 2022 , compared with 2021, as an increase in deferred financing costs and higher commitment fees resulting from the increase in aggregate lender commitments under the Credit Agreement were offset by decreases related to the redemption of the 2025 Senior Secured Notes. Our weighted-average borrowing rate remained flat for the year endedDecember 31, 2022 , compared with 2021, as a result of the timing of redemptions of our Senior Notes during 2022 and 2021. Our weighted-average interest and weighted-average borrowing rates increased for the year endedDecember 31, 2021 , compared with 2020, primarily as a result of the higher interest rate on our 2025 Senior Secured Notes issued during 2020. Our weighted-average interest and weighted-average borrowing rates are impacted by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rate is impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in 50 -------------------------------------------------------------------------------- the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2021 Senior Secured Convertible Notes were retired upon maturity onJuly 1, 2021 , the 2024 Senior Notes were redeemed onFebruary 14, 2022 , and the 2025 Senior Secured Notes were redeemed onJune 17, 2022 . After these dates, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs for the redeemed or retired notes, or for 2021 Senior Secured Convertible Notes and the 2025 Senior Secured Notes, the non-cash amortization of the discounts. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest and early repayments or redemptions; and for repurchases of shares of our common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During 2022, we spent approximately$879.9 million on capital expenditures. This amount differs from the costs incurred amount of$961.7 million for the year endedDecember 31, 2022 , as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts. Please refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion. The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Changes to the Internal Revenue Code ("IRC"), such as the CAMT enacted pursuant to the IRA, effective for tax years beginning afterDecember 31, 2022 , could increase the corporate income tax rate and could eliminate or reduce current tax deductions for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. While the CAMT is not currently applicable to us, it and other future legislation could reduce our net cash provided by operating activities over time, and could therefore result in a reduction of funding available for the items discussed above. We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. OnSeptember 7, 2022 , we announced that our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to$500.0 million in aggregate value of our common stock throughDecember 31, 2024 . We intend to fund repurchases with net cash provided by operating activities. Stock repurchases may also be funded with borrowings under the Credit Agreement. The timing, as well as the number and value of our shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. During the year endedDecember 31, 2022 , we repurchased and subsequently retired 1,365,255 shares of our common stock at a cost of$57.2 million , and as ofDecember 31, 2022 ,$442.8 million remained available under the Stock Repurchase Program for repurchases of our common stock. EffectiveJanuary 1, 2023 , shares of common stock repurchased, net of shares of common stock issued, will be subject to a one percent excise tax imposed by the IRA. The Stock Repurchase Program terminates and supersedes theAugust 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination. Please refer to Note 3 - Equity in Part II, Item 8 of this report for additional discussion. During 2022, we redeemed all of the aggregate principal amount outstanding of our 2024 Senior Notes and our 2025 Senior Secured Notes. During 2021, we issued our 2028 Senior Notes and with the proceeds, repurchased certain of our then outstanding 2022 Senior Notes and 2024 Senior Notes through the Tender Offer. Subsequently, we redeemed the remaining 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. The 2021 Senior Secured Convertible Notes matured onJuly 1, 2021 , and on that day, we used borrowings under our revolving credit facility to retire, at par, the outstanding principal amount. These transactions were completed as part of our strategy to reduce absolute debt and improve our leverage metrics. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions. During the years endedDecember 31, 2022 , 2021, and 2020, we paid$19.6 million ,$2.4 million , and$2.3 million , respectively, in dividends to our stockholders. During 2022, our Board of Directors approved an increase to our fixed dividend to$0.60 per share annually, to be paid in quarterly increments of$0.15 per share. Dividends paid reflects$0.16 per share paid during the year endedDecember 31, 2022 , and$0.02 per share paid during each of the years endedDecember 31, 2021 , and 2020. Our current 51 -------------------------------------------------------------------------------- intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, other covenants, and other factors that could arise. The payment and amount of future dividends remains at the discretion of our Board of Directors.
Analysis of Cash Flow Changes Between 2022 and 2021 and Between 2021 and 2020
The following tables present changes in cash flows between the years endedDecember 31, 2022 , 2021, and 2020, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows ("accompanying statements of cash flows") in Part II, Item 8 of this report.
Operating Activities
For the Years Ended December 31, Amount Change Between
2022 2021 2020 2022/2021 2021/2020
(in millions)
Net cash provided by
operating activities $ 1,686.4 $ 1,159.8 $ 790.9 $ 526.6 $ 368.9
Net cash provided by operating activities increased for the year ended
December 31, 2022 , compared with 2021, primarily as a result of an $833.2
million increase in cash received from oil, gas, and NGL production revenues,
net of transportation costs and production taxes, partially offset by an
increase in cash paid for LOE and G&A expense of $70.7 million and an increase
of $69.2 million in cash paid on settled derivative trades.
Net cash provided by operating activities increased for the year ended
December 31, 2021 , compared with 2020, primarily as a result of a $1.3 billion
increase in cash received from oil, gas, and NGL production revenues, net of
transportation costs and production taxes, partially offset by an increase of
$1.0 billion in cash paid on settled derivative trades.
Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.
Investing Activities
For the Years Ended December 31, Amount Change Between
2022 2021 2020 2022/2021 2021/2020
(in millions)
Net cash used in
investing activities $ (880.3) $ (667.2) $ (555.6) $
(213.1)
Net cash used in investing activities increased for the year endedDecember 31, 2022 , compared with 2021, primarily as a result of a$205.1 million increase in capital expenditures. Net cash used in investing activities during the year endedDecember 31, 2022 , was funded by net cash provided by operating activities. Net cash used in investing activities increased for the year endedDecember 31, 2021 , compared with 2020, primarily as a result of a$127.1 million increase in capital expenditures. Net cash used in investing activities during the year endedDecember 31, 2021 , was funded by net cash provided by operating activities. Financing Activities For the Years Ended December 31, Amount Change Between 2022 2021 2020
2022/2021 2021/2020
(in millions)
Net cash used in
financing activities $ (693.9) $ (159.8) $ (235.4) $ (534.1) $ 75.6
Net cash used in financing activities for the year ended December 31, 2022 ,
related to $480.2 million of cash paid, including premium, to redeem our 2025
Senior Secured Notes, and $104.8 million of cash paid to redeem our 2024 Senior
Notes. These redemptions were made using cash on hand. Additionally, we paid
$57.2 million to repurchase and subsequently retire 1,365,255 shares of our
common stock under the Stock Repurchase Program, $25.1 million for the net share
settlement of employee and director stock awards, and $19.6 million in dividends
to our stockholders. Please refer to Note 3 - Equity in Part II, Item 8 of this
report for additional discussion of our Stock Repurchase Program.
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During the year ended December 31, 2021 , we paid $385.3 million , including net
premiums, to fund the Tender Offer and the 2022 Senior Notes Redemption, and we
received net cash proceeds of $392.8 million from the issuance of our 2028
Senior Notes. Additionally, we paid $65.5 million to retire our 2021 Senior
Secured Convertible Notes and had net repayments under our revolving credit
facility of $93.0 million .
During the year ended December 31, 2020 , we paid $136.5 million to repurchase
certain of our 2022 Senior Notes and 2024 Senior Notes in open market
transactions, we paid $53.5 million to certain holders of the 2021 Senior
Secured Convertible Notes in connection with the Private Exchange, and we had
net repayments under our revolving credit facility of $29.5 million .
Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.
Interest Rate Risk
We are exposed to risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility's fair value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact their fair values. As ofDecember 31, 2022 , our outstanding principal amount of fixed-rate debt totaled$1.6 billion and we had no floating-rate debt outstanding. As we had no borrowings under our revolving credit facility during 2022, we had no exposure to variable interest rates during the year endedDecember 31, 2022 . Please refer to Note 8 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes. TheFederal Reserve increased short-term interest rates throughout 2022 and into early 2023. These increases, and any future increases, could impact the cost and our ability to borrow funds.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, ability to execute our Stock Repurchase Program and pay dividends, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility related to the ongoing conflict betweenRussia andUkraine , the economic and trade sanctions that certain countries have imposed onRussia , production output from OPEC+, and the associated potential impacts of these issues on global commodity and financial markets. These issues have contributed to inflation, supply chain disruptions, a rise in interest rates, and could have further industry-specific impacts, which may require us to adjust our business plan. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2022 production, a 10 percent decrease in our average realized prices for oil, gas, and NGLs, would have reduced our oil, gas, and NGL production revenues by approximately$227.0 million ,$79.1 million , and$28.5 million , respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the year endedDecember 31, 2022 , would have offset the declines in oil, gas, and NGL production revenue by approximately$157.9 million . We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As ofDecember 31, 2022 , a 10 percent increase or decrease in the forward curves associated with our oil and gas commodity derivative instruments would have changed our net derivative positions for these products by approximately$61.1 million and$1.9 million , respectively.
Off-Balance Sheet Arrangements
We have not participated in transactions that generate relationships with
unconsolidated entities or financial partnerships, such as entities often
referred to as structured finance or special purpose entities ("SPE" or "SPEs"),
which would have been established for the purpose of facilitating off-balance
sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities
exist. If we determine that we are the primary beneficiary of a variable
interest entity, that entity is consolidated into our consolidated financial
statements. We have not been involved in any unconsolidated SPE transactions
during 2022 or 2021, or through the filing of this report.
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--------------------------------------------------------------------------------Critical Accounting Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment. Successful Efforts Method of Accounting. GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report. Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations. Please refer to Oil and Gas Producing Activities in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engageRyder Scott , an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as ofDecember 31, 2022 , is the current market value of our estimated proved reserves. In accordance withSEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period endedDecember 31, 2022 . Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Please refer to Risk Factors in Part I, Item 1A of this report for additional discussion. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified. The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. For the Years Ended December 31, 2022 2021 2020 MMBOE Change Revisions resulting from performance (11.1) 3.4 3.6 Removal of proved undeveloped reserves no longer in our five-year development plan (19.9) (40.6) (65.0) Revisions resulting from price changes 9.5 37.2 (32.6) Total (21.5) - (94.0)
____________________________________________
Note: Amounts may not calculate due to rounding.
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As previously noted, commodity prices are volatile and estimates of reserves are
inherently imprecise. Consequently, we expect to continue experiencing these
types of changes.
We cannot reasonably predict future commodity prices, although we believe that
together, the below analyses provide reasonable information regarding the impact
of changes in pricing and trends on total estimated proved reserves. The
following table reflects the estimated MMBOE change and percentage change to our
total reported estimated proved reserve volumes from the described hypothetical
changes:
For the year ended December 31, 2022
MMBOE Change Percentage Change
10 percent decrease in SEC pricing (1) (3.7) (1) %
Average NYMEX strip pricing as of fiscal
year end (2) (14.3) (3) %
10 percent decrease in proved
undeveloped reserves (3) (22.0) (4) %
____________________________________________
(1) The change solely reflects the impact of a 10 percent decrease inSEC pricing to the total reported estimated proved reserve volumes as ofDecember 31, 2022 , and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. (2) The change solely reflects the impact of replacingSEC pricing with the five-year average NYMEX strip pricing as ofDecember 31, 2022 , and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As ofDecember 31, 2022 ,SEC pricing was$93.67 per Bbl for oil,$6.36 per MMBtu for gas, and$42.52 per Bbl for NGLs, and five-year average NYMEX strip pricing was$71.02 per Bbl for oil,$4.38 per MMBtu for gas, and$28.05 per Bbl for NGLs. (3) The change solely reflects a 10 percent decrease in proved undeveloped reserves as ofDecember 31, 2022 , and does not include any additional impacts to our estimated proved reserves. Additional reserve information can be found in Reserves in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report. Impairment ofOil and Gas Properties . Proved oil and gas properties are evaluated for impairment on a pool-by-pool basis and reduced to fair value when events or changes in circumstances indicate that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. Unproved oil and gas properties are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties using a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as ofFebruary 9, 2023 , we do not expect any material oil and gas property impairments in the first quarter of 2023 resulting from commodity price impacts. Please refer to Note 1 - Summary of Significant Accounting Policies and Note 8 - Fair Value Measurements in Part II, Item 8 of this report for discussion of impairments of oil and gas properties recorded for the years endedDecember 31, 2022 , 2021, and 2020. Revenue Recognition. We predominately derive our revenue from the sale of produced oil, gas, and NGLs. Our revenue recognition policy is a critical accounting estimate because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. A 10 percent change in our revenue accrual at year-end 2022 would have impacted total operating revenues by approximately$18.4 million for the year endedDecember 31, 2022 . Please refer to Note 1 - Summary of Significant Accounting Policies and Note 2 - Revenue from Contracts with Customers in Part II, Item 8 of this report for additional discussion. 55 -------------------------------------------------------------------------------- Derivative Financial Instruments. We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to oil, gas, and NGL price volatility and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss). The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Please refer to Note 1 - Summary of Significant Accounting Policies and Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. Income Taxes. We account for deferred income taxes, whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using currently enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. We record deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement as well as significant enacted tax rate changes could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by approximately$14.0 million for the year endedDecember 31, 2022 . Please refer to Note 1 - Summary of Significant Accounting Policies and Note 4 - Income Taxes in Part II, Item 8 of this report for additional discussion.
Accounting Matters
Please refer to Recently Issued Accounting Standards in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for information on new authoritative accounting guidance.
Environmental
We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations. Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, please refer to Risk Factors - Risks Related to Oil and Gas Operations and the Industry - Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Climate Change and Air Quality. InJune 2013 ,President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, onMay 12, 2016 , theEPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds ("VOCs" or "VOC") and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed afterSeptember 18, 2015 . The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. OnSeptember 14 , and 15, 2020, theEPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. InNovember 2021 , theEPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources. InDecember 2022 , theEPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. TheEPA is expected to finalize the rule in 2023. States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion ("ppb") in 2015. TheEPA maintained the standard in 2020, but in 2021 theEPA communicated that it is reconsidering the 2020 decision with the intention of completing the reconsideration by the end of 2023. If 56 -------------------------------------------------------------------------------- the ozone NAAQS is lowered, it may result in additional actions by states requiring further emission controls and associated costs. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance. TheUnited States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, there have been international conventions and efforts to establish standards for the reduction of GHGs globally, including theParis accords inDecember 2015 . The conditions for entry into force of theParis accords were met onOctober 5, 2016 and the Agreement went into force 30 days later onNovember 4, 2016 . At theUnited Nations Climate Change Conference inGlasgow in 2021,the United States and theEuropean Union announced the Global Methane Pledge that aims to reduce methane emissions by 30 percent compared with 2020 levels. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth's atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations. In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. Approximately 40 percent and 35 percent of our production on a BOE basis in 2022 and 2021, respectively, was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest
income, income taxes, depletion, depreciation, amortization and asset retirement
obligation liability accretion expense, exploration expense, property
abandonment and impairment expense, non-cash stock-based compensation expense,
derivative gains and losses net of settlements, gains and losses on
divestitures, gains and losses on extinguishment of debt, and certain other
items. Adjusted EBITDAX excludes certain items that we believe affect the
comparability of operating results and can exclude items that are generally
non-recurring in nature or whose timing and/or amount cannot be reasonably
estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides
useful additional information to investors and analysts, as a performance
measure, for analysis of our ability to internally generate funds for
exploration, development, acquisitions, and to service debt. We are also subject
to financial covenants under our Credit Agreement as further described in Note 5
- Long-Term Debt in Part II, Item 8 of this report. In addition, adjusted
EBITDAX is widely used by professional research analysts and others in the
valuation, comparison, and investment recommendations of companies in the oil
and gas exploration and production industry, and many investors use the
published research of industry research analysts in making investment decisions.
Adjusted EBITDAX should not be considered in isolation or as a substitute for
net income (loss), income (loss) from operations, net cash provided by operating
activities, or other profitability or liquidity measures prepared under GAAP.
Because adjusted EBITDAX excludes some, but not all items that affect net income
(loss) and may vary among companies, the adjusted EBITDAX amounts presented may
not be comparable to similar metrics of other companies. Our revolving credit
facility provides a material source of liquidity for us. Under the terms of our
Credit Agreement, if we failed to comply with the covenants that establish a
maximum permitted ratio of total funded debt, as defined in the Credit
Agreement, to adjusted EBITDAX, we would be in default, an event that would
prevent us from borrowing under our revolving credit facility and would
therefore materially limit a significant source of our liquidity. In addition,
if we are in default under our revolving credit facility and are unable to
obtain a waiver of that default from our lenders, lenders under that facility
and under the indentures governing each series of our outstanding Senior Notes,
as defined in Note 5 - Long-Term Debt in Part II, Item 8 of this report, would
be entitled to exercise all of their remedies for default.
57
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The following table provides reconciliations of our net income (loss) (GAAP) and
net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP)
for the periods presented:
For the Years Ended December 31,
2022 2021 2020
(in thousands)
Net income (loss) (GAAP) $ 1,111,952 $ 36,229 $ (764,614)
Interest expense 120,346 160,353 163,892
Income tax expense (benefit) 283,818 9,938 (192,091)
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion 603,780 774,386 784,987
Exploration (1) 50,978 35,346 37,541
Impairment 7,468 35,000 1,016,013
Stock-based compensation expense 18,772 18,819 14,999
Net derivative (gain) loss 374,012 901,659 (161,576)
Derivative settlement gain (loss) (710,700) (748,958) 351,261
Net (gain) loss on extinguishment of debt 67,605 2,139 (280,081) Other, net (9,743) 507 5,074 Adjusted EBITDAX (non-GAAP) 1,918,288 1,225,418 975,405 Interest expense (120,346) (160,353) (163,892) Income tax (expense) benefit (283,818) (9,938) 192,091 Exploration (1)(2) (36,810) (35,346) (37,541) Amortization of debt discount and deferred financing costs 10,281 17,275 17,704 Deferred income taxes 269,057 9,565 (192,540) Other, net 1,817 (4,260) (11,874) Net change in working capital (72,063)
117,411 11,591
Net cash provided by operating activities (GAAP)
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(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense. (2) For the year endedDecember 31, 2022 , amount is net of certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of operation.
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