DEVON ENERGY CORP/DE (DVN) FY 2022 MD&A

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

The following discussion and analyses primarily focus on 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this report can be found 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.

Executive Overview

Looking across our 2021 and 2022 performance, the Merger has helped us become a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerated our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. In the third quarter of 2022, we acquired additional producing properties and leasehold interests in both the Williston Basin and Eagle Ford that are complementary to our existing acreage, offer operational synergies and add high-quality inventory. Additionally, our diverse portfolio balances exposure to oil and natural gas prices with access to premium markets to improve realized pricing.

We remain focused on building economic value by executing on our strategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our 2022 performance highlights for these priorities include the following items:

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Generated $8.5 billion of operating cash flow in 2022, which is a 74% increase from the prior year.

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2022 oil production averaged 299 MBbls/d, which is a 3% increase from the prior year.

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As of December 31, 2022, completed approximately 65% of our authorized $2.0 billion share repurchase program, with 25.7 million of our common shares repurchased for $1.3 billion, or $50.90 per share, since inception of the plan.

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Exited 2022 with $4.5 billion of liquidity, including $1.5 billion of cash.

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Including variable dividends, paid dividends of approximately $3.4 billion in 2022 and have declared $579 million of dividends to be paid in the first quarter of 2023, which is inclusive of an 11% increase to our fixed quarterly dividend to $0.20 per share.

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Invested approximately $100 million in emissions reduction capital projects in 2022.

We remain committed to capital discipline and delivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from recent geopolitical events.

Commodity prices strengthened in 2021 and continued to strengthen throughout the majority of 2022, which has significantly improved our earnings and cash flow generation. The increase in commodity prices was primarily driven by increased demand resulting from the recovery from the COVID-19 pandemic. The military conflict between Russia and Ukraine and related economic sanctions imposed on Russia, as well as OPEC+ restraining production growth, further exacerbated supply shortages, causing oil

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prices to increase even more throughout most of 2022. However, oil prices did begin to decline in the fourth quarter of 2022 due to economic uncertainty surrounding inflation and increased interest rates as well as certain geopolitical events.

Trends of our annual earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The annual earnings chart and cash flow chart present amounts pertaining to Devon’s continuing operations. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

Our earnings in 2020 were negatively impacted by lower commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. Earnings improved significantly in 2021 due to commodity prices recovering from the initial COVID-19 pandemic as well as the Merger closing in January 2021. Earnings continued to improve

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during 2022 as commodity prices continued to strengthen and we executed on our strategic priorities as a company. Led by a 73% and 39% increase in Henry Hub and WTI from 2021 to 2022, respectively, our unhedged combined realized price rose 38%. Additionally, volumes increased 7% from 2021 to 2022 primarily due to the continued development of assets in the Delaware Basin and acquisitions in the Williston Basin and Eagle Ford that both closed in the third quarter of 2022.

Our net earnings in recent years have been significantly impacted by asset impairments and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in both 2020 and 2021 included a $0.1 billion hedge valuation loss, net of taxes and 2022 included a $0.5 billion hedge valuation gain, net of taxes. Additionally, net earnings in 2020 included $2.2 billion of asset impairments on our proved and unproved properties, net of taxes, due to reduced demand from the COVID-19 pandemic. Excluding these amounts, our core earnings have been more stable over recent years but continue to be heavily influenced by commodity prices.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. We have continued to deliver strong cash flow and EBITDAX results primarily due to improved commodity prices and overall market conditions as well as strong operating performance.

We exited 2022 with $4.5 billion of liquidity, comprised of $1.5 billion of cash and $3.0 billion of available credit under our Senior Credit Facility. We currently have $6.4 billion of debt outstanding, of which approximately $250 million is classified as short-term. We currently have approximately 25% and 20% of our oil and gas production hedged, respectively, for 2023. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.

As commodity prices and our operating performance strengthen and bolster our financial condition, we have authorized opportunistic repurchases of up to $2.0 billion of our common shares with an expiration date of May 4, 2023. We repurchased approximately 11.7 million shares during 2022 for approximately $718 million, or $61.36 per share. As of December 31, 2022, we have repurchased approximately 25.7 million shares for approximately $1.3 billion, or $50.90 per share, since the inception of the program. Additionally, we continue funding our fixed plus variable dividends, which totaled $3.4 billion in 2022. We recently declared a dividend payable in the first quarter of 2023 for $579 million, which includes an 11% increase to our fixed quarterly dividend to $0.20 per share.

Business and Industry Outlook

In 2022, Devon marked its 51st anniversary in the oil and gas business and its 34th year as a public company. The strength of our portfolio of assets, the success of our 2021 transformational merger with WPX and strong commodity prices led us to generate net earnings of $6 billion in 2022, which was more than double that of 2021. Our portfolio was further strengthened in 2022 following the completion of two bolt-on acquisitions in the Williston Basin and Eagle Ford that were highly complementary to our existing positions in each basin. Both acquisitions were funded with cash on hand, and our balance sheet and financial position remains strong following the acquisitions. We remain committed to continuing our track record of industry leading return of capital to our shareholders, underpinned by low capital reinvestment rates and a disciplined, returns-driven strategy which is designed to be successful through

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economic cycles. In line with this strategy, we returned over $4 billion of cash to shareholders through fixed and variable cash dividends and share repurchases in 2022.

In 2022, WTI oil prices averaged $94.39 per Bbl versus $67.86 per Bbl in 2021. Crude prices experienced significant improvement from the prior year, but volatility remained. Current market fundamentals indicate that even though the supply-demand balance for commodities is expected to remain tight due to growing demand and continued discipline by oil producers, market prices for crude oil and natural gas are expected to be lower in 2023 due to ongoing recession fears driven by high inflation levels and rising interest rates. Additionally, commodity prices could remain volatile as uncertainty still exists from the impact of sanctioned Russian oil in the global market, as well as actions taken by OPEC+ countries in supporting a balanced global crude supply. Henry Hub natural gas prices continued to strengthen in 2022, averaging $6.65 per Mcf compared to $3.85 per Mcf in 2021. Natural gas prices rebounded in 2022 due to increased demand, continued capital discipline by producers, high LNG prices and infrastructure constraints. Looking forward to 2023, natural gas and NGL prices are expected to decline compared to 2022 due to limited LNG export capacity coming online, rising U.S. natural gas production and sufficient storage levels. Our 2023 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 25% of our anticipated oil volumes and 20% of our anticipated gas volumes. Further insulating our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges to protect price realizations across our portfolio.

We expect to continue our capital-efficiency focus and our steadfast commitment to capital discipline with our 2023 capital program which is expected to maintain our oil production at similar levels as 2022, adjusted for acquisitions. To achieve our 2023 capital program objectives that maximize free cash flow, approximately 60% of our 2023 spend is expected to be allocated to our highest margin U.S. oil play, the Delaware Basin. We expect to continue to leverage the strengths of our multi-basin strategy and deploy the remainder of our 2023 capital in our other core areas of Eagle Ford, Anadarko Basin, Powder River Basin and Williston Basin. Our 2023 capital is expected to be higher than last year partly due to a full year of planned capital spend on assets acquired during 2022. Additionally, the estimated impact of inflation has also been accounted for in our 2023 capital and operating costs forecasts. The currently elevated level of cost inflation could erode our cost efficiencies gained over previous years and pressure our margin in 2023, particularly if commodity prices decline. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow. We expect to mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.

Results of Operations

The following graph, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Analysis of the change in net earnings is shown below.

Our 2022 net earnings were $6.0 billion, compared to net earnings of $2.8 billion for 2021. The graph below shows the change in net earnings from 2021 to 2022. The material changes are further discussed by category on the following pages.

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Production Volumes

From 2021 to 2022, the change in volumes contributed to a $488 million increase in earnings. The increase in volumes was primarily due to continued development in the Delaware Basin and acquisitions in the Williston Basin and Eagle Ford that both closed in the third quarter of 2022. These increases were partially offset by natural declines in legacy Williston Basin assets and the Power River Basin.

Realized Prices

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From 2021 to 2022, realized prices contributed to a $4.1 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to oil and gas commodities.

Hedge Settlements

(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Production Expenses

LOE and gathering, processing and transportation expenses increased primarily due to inflation and higher volumes resulting from increased activity and acquisitions in the Williston Basin and Eagle Ford. Production and property taxes also increased due to higher commodity prices.

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Field-Level Cash Margin

The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL revenues less production expenses and is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 7. The changes in production volumes, realized prices and production expenses, shown above, had the following impacts on our field-level cash margins by asset.

DD&A

DD&A increased in 2022 primarily due to higher volumes which was partially offset by lower DD&A rates. The decrease in DD&A rates was primarily due to an increase in oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices.

General and Administrative Expense

Other Items

(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves.

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In 2022, asset dispositions include $42 million related to the re-valuation of contingent earnout payments associated with divested Barnett Shale assets. 2021 asset dispositions include $110 million related to the re-valuation of contingent earnout payments associated with divested Barnett Shale assets as well as $39 million related to the sale of non-core assets in the Rockies. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Net financing costs decreased due to debt retirements in 2021 which was partially offset by a $30 million gain associated with those retirements. Additionally, net financing costs also decreased in 2022 due to an increase in interest income resulting from an increase in interest rates. For additional information, see Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report.

Restructuring and transaction costs in 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. For additional information, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

For discussion on other, net, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.

Income Taxes

For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report. In 2023, our total effective income tax rate is expected to remain relatively consistent with that for 2022. However, due to reduced net operating loss carryforwards and potential effects from the IRA, our current income tax rate could increase noticeably in 2023. While our 2022 current income tax rate was 7%, we expect our 2023 current income tax rate could approach the mid-teens, depending on commodity prices among other factors.

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Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the time periods presented below.

Operating Cash Flow and WPX Acquired Cash

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow increased 74% during 2022 compared to 2021. The increase was primarily due to significantly increased commodity prices as well as higher volumes for 2022 compared to 2021.

Acquisitions of Property and Equipment

During 2022, we paid $2.6 billion toward acquisitions of producing properties and leasehold interests located in the Eagle Ford and Williston Basin, which were completed in the third quarter of 2022. For additional information, please see Note 2 in “Part II. Item 8. Financial Statements and Supplementary Data” in this report.

Divestitures of Property and Equipment

During 2022 we received contingent earnout payments related to assets previously sold. For additional information, please see Note 2 in “Part II. Item 8. Financial Statements and Supplementary Data” in this report.

During 2021, we sold non-core U.S. upstream assets for approximately $79 million.

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Capital Expenditures

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our capital expenditures for 2022 represent approximately 30% of our operating cash flow.

Investment Activity

During 2022 and 2021, Devon received distributions from our investments of $39 million and $35 million, respectively. Devon contributed $76 million and $25 million to our investments during 2022 and 2021, respectively. The 2022 contributions primarily related to our investment in Matterhorn.

Debt Activity

Subsequent to the Merger closing, we redeemed $1.2 billion of senior notes in 2021. We also paid $59 million of cash retirement costs related to these redemptions.

Repurchases of Common Stock and Shareholder Distributions

We repurchased 11.7 million shares of common stock for $718 million in 2022 and 14 million shares of common stock for $589 million in 2021 under share repurchase programs authorized by our Board of Directors. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report.

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The following table summarizes our common stock dividends in 2022 and 2021. In February 2022, our Board of Directors increased our fixed dividend rate by 45% to $0.16 per share and again by 13% to $0.18 per share beginning in the third quarter of 2022. In addition to the fixed quarterly dividend, we paid a variable dividend in each quarter of 2022 and 2021. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Noncontrolling Interest Activity

During 2021, we received $4 million of contributions from our noncontrolling interests (primarily in CDM). During 2022 and 2021, we distributed $30 million and $21 million, respectively, to our noncontrolling interests in CDM. In the first quarter of 2021, we paid $24 million to purchase the noncontrolling interest portion of a partnership that WPX had formed to acquire minerals in the Delaware Basin.

Liquidity

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements, as discussed in this section, as well as execute our cash-return business model.

Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of 2022, we held approximately $1.5 billion of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.

Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other highly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2022 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2023. The currently elevated level of cost inflation could erode our cost efficiencies gained over previous years and pressure our margin in 2023. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices, which is what we experienced in 2022 and 2021. Furthermore, the COVID-19 pandemic has contributed to disruption and volatility in our supply chain, which has resulted, and may continue to result, in labor shortages, increased costs and delays for pipe and other materials needed for our operations as well as increased costs due to inflation. We expect to mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.

Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from joint interest owners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.

Credit Availability

We have $3.0 billion of available borrowing capacity under our Senior Credit Facility at December 31, 2022. The Senior Credit Facility matures on October 5, 2024, with the option to extend the maturity date by two additional one-year periods subject to lender consent. Subsequent to October 5, 2023, the borrowing capacity decreases to $2.8 billion. The Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2022, there were no borrowings under our commercial paper program. See Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of December 31, 2022, we were in compliance with this covenant with a 23% debt-to-capitalization ratio.

Our access to funds from the Senior Credit Facility is not subject to a specific funding condition requiring the absence of a “material adverse effect”. It is not uncommon for credit agreements to include such provisions. In general, these provisions can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement. While our credit agreement includes provisions qualified by material adverse effect as well as a covenant that requires us to report a condition or event having a material adverse effect, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality,

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reserve mix, debt levels, cost structure, planned asset sales and size and scale of our production. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa2 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

There are no “rating triggers” in any of our contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Fixed Plus Variable Dividend

We are committed to a "fixed plus variable" dividend strategy. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. Our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share in February 2022 and again by 13% to $0.18 per share beginning in August 2022. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.

In February 2023, Devon announced a cash dividend in the amount of $0.89 per share payable in the first quarter of 2023. The dividend consists of a fixed quarterly dividend in the amount of $130 million (or $0.20 per share) and a variable dividend in the amount of approximately $449 million (or $0.69 per share).

Share Repurchase Program

Our Board of Directors has authorized a $2.0 billion share repurchase program that expires on May 4, 2023. Through February 10, 2023, we had executed $1.3 billion of the authorized program.

Capital Expenditures

Our 2023 capital expenditure budget is expected to be approximately $3.6 billion to $3.8 billion, which is approximately 35% higher than our 2022 capital expenditures. The anticipated increase in capital spending is driven by a full year of planned capital spend on assets acquired in 2022 and general inflation trends.

Contractual Obligations

As of December 31, 2022, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, retained obligations related to our divested Canadian business, operational agreements, drilling and facility obligations and various tax obligations. As discussed above, we estimate the combination of our sources of capital will continue to be adequate to fund our short- and long-term contractual obligations. See Notes 6, 8, 14, 15, 16 and 20 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

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Oil and Gas Assets Accounting, Classification, Reserves & Valuation

Successful Efforts Method of Accounting and Classification

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2022, all suspended well costs have been suspended for less than one year.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2022, Devon had approximately $777 million of undeveloped leasehold costs. Of the remaining undeveloped leasehold costs at December 31, 2022, none is scheduled to expire in 2023.

Reserves

Our estimates of proved and proved developed reserves are a major component of DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by a third-party petroleum consulting firm. In 2022, 89% of our proved reserves were subjected to such an audit.

The passage of time provides additional information which may result in revisions to previous estimates to reflect updated information. In the past five years, annual revisions other than price to our proved reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. For example, revisions may be driven broadly by economic factors such as significant changes in operating costs, or they may be more focused such as in a given area or reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Valuation of Long-Lived Assets

Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of common operating fields is largely based on geological structural features or stratigraphic condition, which requires judgment. Management also considers the nature of

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production, common infrastructure, common sales points, common processing plants, common regulation and management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment.

Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. The expected future cash flows used for impairment reviews include future production volumes associated with proved producing and risk-adjusted proved undeveloped reserves, and when needed, probable and possible reserves.

Besides the risk-adjusted estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we utilize NYMEX forward strip prices and incorporate internally generated price forecasts along with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues.

We also estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. To measure indicated impairments, we use a market-based weighted-average cost of capital to discount the future net cash flows. Changes to any of the reserves or market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

Reduced demand from the COVID-19 pandemic and management of production levels from OPEC+ caused WTI pricing to decrease more than 60% during the first quarter of 2020. As a result, we reduced our planned 2020 capital investment 45%. With materially lower commodity prices and reduced near-term investment, we assessed all our oil and gas fields for impairment as of March 31, 2020 and recognized proved and unproved impairments totaling $2.8 billion. The impairments relate to our Anadarko Basin and Rockies fields in which our basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than the first quarter of 2020.

As a result of the impairments recognized in 2020 and the significant increases in commodity prices during 2021 which sustained through 2022, none of our oil and gas assets were at risk of impairment as of December 31, 2022.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Due to significant increases in commodity pricing and projections of future income, in the fourth quarter of 2021, Devon reassessed its evaluation of the realizability of deferred tax assets in future years and determined that a U.S. federal valuation allowance was no longer necessary. As such, Devon removed its remaining U.S. federal valuation allowance.

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change occurred during 2022 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next year. See Note 8 in “Item 8. Financial Statements and Supplementary Data” in this report for further discussion regarding our net operating losses and tax credits available to be carried forward and used in future years. Devon continues to maintain valuation allowances for certain state and foreign deferred tax assets.

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On August 16, 2022, the IRA was signed into law and included various income tax related provisions with an effective date beginning in 2023. Among the enacted provisions are a 15% corporate alternative minimum tax (“CAMT”) and several new and expanded clean energy credits and incentives. The CAMT will be assessed on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for the preceding three consecutive years. The Company continues to assess the potential impact of the CAMT, and material incremental cash tax could be incurred depending on actual operating results as well as future U.S. Treasury guidance.

Purchase Accounting

Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger with WPX. In connection with the Merger in 2021, as the accounting acquirer, we allocated the $5.4 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the date of the Merger.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions related to the estimated fair values of proved and unproved oil and gas properties. Since sufficient market data was not available regarding the fair values of proved and unproved oil and gas properties, we prepared estimates and engaged third-party valuation experts. Significant judgments and assumptions were inherent in these estimates and included, among other things, estimates of reserve quantities, estimates of future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflected the risk of the underlying cash flow estimates.

Estimated fair values ascribed to assets acquired can have a significant impact on future results of operations presented in Devon’s financial statements. A higher fair value ascribed to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserve quantities, development costs and operating costs. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.

In addition to the fair value of proved and unproved oil and gas properties, other fair value assessments for the assets acquired and liabilities assumed in the Merger related to debt, the equity method investment in Catalyst and out-of-market contract liabilities. The fair value of the assumed WPX publicly traded debt was based on available third-party quoted prices. We prepared estimates and engaged third-party valuation experts to assist in the valuation of the equity method investment in Catalyst. Significant judgments and assumptions inherent in this estimate included projected Catalyst cash flows, comparable companies cash flow multiples and an estimate of an applicable market participant discount rate. The fair value of assumed out-of-market contract assets and liabilities associated with longer-term marketing, gathering, processing and transportation contracts included significant judgments and assumptions related to determining the market rates, estimates of future reserves and production associated with the respective contracts and applying an applicable market participant discount rate.

Non-GAAP Measures

Core Earnings

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2022 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings (loss) excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our quarterly financial results. For more information on the results of discontinued operations for our Barnett Shale assets, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2022 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance and fair value changes in derivative financial instruments.

Amounts excluded for 2021 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance, changes in tax legislation, fair value changes in derivative financial instruments, restructuring and transaction costs associated with the workforce reductions in 2021 and costs associated with the early retirement of debt.

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Amounts excluded for 2020 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance, fair value changes in derivative financial instruments and foreign currency, change in tax legislation and restructuring and transaction costs associated with the workforce reductions in 2020.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.

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EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.

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Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.

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