DEVON ENERGY CORP/DE (DVN) FY 2021 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 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 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 2020 Annual Report on Form 10-K.

Executive Overview

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 accelerates our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. We remain focused on building economic value by executing on our strategic priorities of achieving disciplined oil volume growth, capturing operational and corporate synergies, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items:

We operate under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and value to our shareholders and continuing our commitment to ESG excellence, which provides us with a strong foundation to grow returns, margin and profitability. We continue to execute on our strategy and navigate through various economic environments by protecting our financial strength, maintaining a commitment to capital discipline, improving our cash cost structure and preserving operational continuity.

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Commodity prices strengthened throughout 2021 which significantly improved our earnings and cash flow generation. The increase in commodity prices was primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic, as well as OPEC+ and other oil and natural gas producers not rapidly increasing current production levels.

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. Led by an 85% and 71% increase in Henry Hub and WTI from 2020 to 2021, respectively, our unhedged combined realized price rose 107%. Additionally, volumes increased 72% from 2020 to 2021 primarily due to the Merger as well as continued development of assets in the Delaware Basin.

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 2019, 2020 and 2021 included a $0.5 billion, $0.1 billion and $0.1 billion hedge

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valuation loss, respectively, 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. Our cash flow and EBITDAX increased from 2020 to 2021 primarily due to the higher commodity prices and the increase in sold volumes driven by the Merger and improved post-merger operating performance.

We exited 2021 with $5.3 billion of liquidity, comprised of $2.3 billion of cash and $3.0 billion of available credit under our Senior Credit Facility. We currently have $6.5 billion of debt outstanding with no maturities until August 2023. We currently have approximately 20% and 30% of our 2022 oil and gas production hedged, respectively. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub and NYMEX last day natural gas indices. 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 $1.6 billion shares of our common stock through the end of 2022. We repurchased approximately 14 million shares in the fourth quarter of 2021 for approximately $589 million or $42.15 per share. Additionally, we continue funding our fixed plus variable dividends, which totaled $1.3 billion in 2021. We recently declared a dividend payable in the first quarter of 2022 for $663 million.

Business and Industry Outlook

In 2021, Devon marked its 50th anniversary in the oil and gas business and its 33rd year as a public company. On January 7, 2021, we completed a transformational merger of equals with WPX, which nearly doubled the size and scale of Devon’s oil production while further strengthening our leadership team, the quality of our portfolio of assets and our balance sheet. During 2021, we successfully integrated the two companies, capturing our targeted merger synergies and delivering strong financial and operational results to generate $4.9 billion of operating cash flow for the year.

The strategic combination with WPX has accelerated our cash return business model that includes reduced capital reinvestment rates and a disciplined, returns-driven strategy to generate higher free cash flow. In line with this business model, we redeemed $1.2 billion of debt and returned nearly $2 billion of cash to shareholders through our fixed plus variable cash dividends and share repurchases. Additionally, our margins have benefited from merger-related synergies, with approximately $600 million in total annual savings, including overhead synergies and interest cost savings from completed debt reductions.

Our disciplined strategy is in response to current market fundamentals that indicate a continued recovery in global oil demand along with an outlook for strong market prices for crude oil and natural gas that also remain inherently volatile. In 2021, WTI oil prices averaged $67.86 per barrel versus $39.59 per barrel in 2020. Crude prices experienced significant improvement from the prior year, but volatility remained due to OPEC oil supply uncertainty and market fears from new COVID-19 variants that could risk the global recovery from the pandemic. Looking ahead, current market fundamentals indicate that 2022 crude pricing is expected to continue to stabilize, supported both by a continued recovery in global demand with the easing of travel restrictions and expected continued capital discipline by oil producers. However, uncertainty still exists depending on new COVID-19 variants, as well as

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actions taken by OPEC+ countries in supporting a balanced global crude supply. Natural gas prices rebounded in 2021 due to continued global economic recovery, supply constraints and production declines. U.S. liquefied natural gas exports also strengthened in 2021 with increased spot prices in Asia and Europe due to increased demand as a result of lifting COVID-19 restrictions and unplanned outages at liquefied natural gas export facilities in other countries. Looking forward, natural gas and NGL prices are expected to flatten or decrease due to slowing growth in liquefied natural gas exports, rising U.S. natural gas production and warmer-than-expected weather.

Our strategy of spending well within cash flow mitigates risks to our financial strength due to commodity market volatility and provides for a lower level of hedging. Our 2022 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 20% of our anticipated oil volumes and 30% 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.

With our 2022 capital program, we expect to continue our capital-efficiency focus and our steadfast commitment to capital discipline. To achieve our 2022 capital program objectives that maximize free cash flow, approximately 75% of our 2022 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 2022 capital in our remaining core areas of Eagle Ford, Anadarko Basin, Powder River Basin and Williston Basin. In total, our 2022 operating plan is expected to maintain our oil production at similar levels as 2021. However, some of our capital cost efficiencies could be eroded by global supply chain disruptions, and demand growth which have led to rising levels of cost inflation that could also impact our capital and operating costs. Despite these pressures, our capital forecasts account for the estimated impact of such cost inflation and we expect to continue generating material amounts of free cash flow at current commodity price levels.

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 from continuing operations is shown below.

Our 2021 net earnings were $2.8 billion, compared to a net loss of $2.5 billion for 2020. The graph below shows the change in net earnings (loss) from 2020 to 2021. The material changes are further discussed by category on the following pages.

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Production Volumes

From 2020 to 2021, the change in volumes contributed to a $2.2 billion increase in earnings. Due to the Merger closing on January 7, 2021, volumes now include WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Volumes associated with these WPX legacy assets were approximately 229 MBoe/d for 2021. Continued development of Devon legacy assets in the Delaware Basin also increased volumes. These increases were partially offset by reduced activity across Devon’s remaining legacy assets.

Realized Prices

From 2020 to 2021, realized prices contributed to a $4.7 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 all products in 2021.

Hedge Settlements

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.

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Production Expenses

Production expenses increased primarily due to the Merger closing on January 7, 2021. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report. Partially offsetting increases to gathering, processing and transportation costs were approximately $60 million of Anadarko volume commitments which expired at the end of 2020. Production taxes also increased due to the rise of commodity prices.

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 and Asset Impairments

DD&A increased in 2021 primarily due to the Merger closing on January 7, 2021. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Asset impairments were $2.7 billion in 2020 due to significant decreases in commodity prices resulting primarily from the COVID-19 pandemic. For additional information, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

General and Administrative Expense

Labor and benefits increased primarily due to the Merger closing on January 7, 2021. However, Devon’s G&A per Boe rate decreased 32% primarily due to synergies resulting from the Merger.

Other Items

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.

Exploration expenses decreased primarily due to unproved asset impairments of $152 million in 2020. For additional information, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

Asset dispositions includes $110 million related to the re-valuation of contingent earnout payments associated with our divested Barnett Shale assets and $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.

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Net financing costs increased as a result of the WPX debt assumed in the Merger, partially offset by a $30 million gain associated with our debt retirements in 2021. For additional information, see Note 2 and 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. Restructuring and transaction costs in 2020 relate to workforce reductions, the associated employee severance benefits related to cost reduction plans and approximately $8 million of transaction costs related to the Merger. For additional information, see Note 6 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.

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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 235% during 2021 compared to 2020. The increase was due to the Merger and commodity prices significantly increasing in 2021, as well as cost synergies captured after the Merger.

Divestitures of Property and Equipment

During 2021 and 2020, we sold non-core U.S. upstream assets for approximately $79 million and $34 million, respectively.

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. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. Capital expenditures increased in 2021 primarily due to the Merger closing on January 7, 2021 and results now include activity related to WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Our capital program is designed to operate within operating cash flow. This is evidenced by our operating cash

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flow fully funding capital expenditures for 2021 and 2020. Our capital investment program is driven by a disciplined allocation process focused on maximizing returns.

Debt Activity, Net

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 14 million shares of common stock for $589 million in 2021 and 2.2 million shares of common stock for $38 million in 2020 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.

The following table summarizes our common stock dividends in 2021 and 2020. We raised our quarterly dividend by 22% to $0.11 per share in the second quarter of 2020. In addition to the fixed quarterly dividend, we paid a variable dividend in each quarter of 2021 and a special dividend in 2020 to shareholders on October 1, 2020. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Noncontrolling Interest Activity, net

During 2021, we received $4 million of contributions from our noncontrolling interests (primarily in CDM) and distributed $21 million 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.

During 2020, we received $21 million in contributions from our noncontrolling interests in CDM and distributed $14 million to our noncontrolling interests in CDM.

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.

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. With the Merger, we accelerated our transition to a cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders. These principles will position Devon to be a consistent builder of economic value through the cycle. The post-merger scalability enhanced Devon’s free cash flow, credit profile and decreased the overall cost of capital.

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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 accelerate 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 2021, we held approximately $2.3 billion of cash, inclusive of $160 million of cash restricted primarily for retained obligations related to divested assets. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as these variables 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, 2021 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, as commodity prices have increased, we remain committed to a maintenance capital program for the foreseeable future. We do not intend to add any growth projects until market fundamentals recover, excess inventory clears up and OPEC+ curtailed volumes are effectively absorbed by the world markets.

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. Furthermore, the COVID-19 pandemic has contributed to disruption and volatility in our supply chain, which has resulted, and may continue to result, in increased costs and delays for pipe and other materials needed for our operations.

Merger Synergies – We realized a $600 million reduction of annualized cost savings from synergies resulting from the Merger through cost reductions and efficiencies related to our capital programs, G&A, financing costs and production expenses. Approximately 35% of the reduced costs were related to our capital programs and the remainder relate to our operating expenses, including G&A, interest expense and production expenses.

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.

Repayment of Debt

In conjunction with the Merger, we assumed a principal value of $3.3 billion of WPX debt. Subsequent to the Merger closing, we have reduced our debt by approximately $1.2 billion. We expect these redemptions to lower our annual cash net financing costs by approximately $70 million. We have no debt maturities until 2023.

Credit Availability

We have $3.0 billion of available borrowing capacity under our Senior Credit Facility at December 31, 2021. 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

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billion of short-term credit under our commercial paper program. As of December 31, 2021, 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, 2021, we were in compliance with this covenant with a 25% 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, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB- with a positive outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa3 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

Following the closing of the Merger, we initiated a new “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. In February 2022, our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share. 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, COVID-19 impacts and other factors deemed relevant by the Board. Devon paid $1.3 billion of total fixed and variable dividends during 2021.

In February 2022, Devon announced a cash dividend in the amount of $1.00 per share payable in the first quarter of 2022. The dividend consists of a fixed quarterly dividend in the amount of $106 million (or $0.16 per share) and a variable dividend in the amount of approximately $557 million (or $0.84 per share).

Share Repurchase Program

In February 2022, our Board of Directors increased our share repurchase program by an additional $0.6 billion. The $1.6 billion program expires December 31, 2022 and in the fourth quarter of 2021 we executed $0.6 billion of the authorized program.

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Capital Expenditures

Our 2022 capital expenditure budget is expected to be approximately $2.1 billion to $2.4 billion.

Contractual Obligations

As of December 31, 2021, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, retained obligations related to our Barnett Shale assets and 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, including the obligations we assumed through the Merger. 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.

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, 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 relate 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 are inherent in these estimates and include, 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 reflects 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 relate 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.

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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, 2021, 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, 2021, Devon had approximately $733 million of undeveloped leasehold costs. Of the remaining undeveloped leasehold costs at December 31, 2021, approximately $19 million is scheduled to expire in 2022. The leasehold expiring in 2022 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

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 2021, 88% of our reserves were subjected to such an audit.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our 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. The data for a given reservoir may also 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 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.

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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, none of our oil and gas assets were at risk of impairment as of December 31, 2021.

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 has occurred during 2021 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 two years. 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.

Goodwill

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of goodwill is less than its carrying amount. As part of our qualitative assessment, we considered the general macro-economic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers and stock performance. If the qualitative assessment determines that a

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quantitative goodwill impairment test is required, then the fair value is compared to the carrying value. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analysis including comparable companies and transactions and premiums paid. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions.

Because the trading price of our common stock decreased 73% during the first quarter of 2020 in response to the COVID-19 pandemic, we performed a goodwill impairment test as of March 31, 2020. The two most critical judgments included in the March 31, 2020, test were the period utilized to determine Devon’s market capitalization and the control premium. For the test performed as of March 31, 2020 we derived our market capitalization by using our average common stock price from the latter two thirds of March 2020 to align with the time in the quarter subsequent to a key OPEC+ meeting and the date COVID-19 was officially classified as a pandemic. We applied a control premium based on recent comparable market transactions. We concluded an impairment was not required as of March 31, 2020. For the remainder of 2020, no impairment was required as Devon’s common stock price increased 129% subsequent to the end of the first quarter of 2020. Furthermore, based on our qualitative assessment as of October 31, 2021, no impairment occurred in 2021.

Although our common stock price and commodity prices have increased significantly during 2021, we are subject to commodity price volatility. A sustained period of depressed commodity prices would adversely affect our estimates of future operating results, which could result in future goodwill impairments due to the potential impact on the cash flows of our operations. The impairment of goodwill has no effect on liquidity or capital resources. However, it would adversely affect our results of operations in the period recognized.

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 2021 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 and Canadian operations, 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 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, costs associated with the early retirement of debt and restructuring and transaction costs associated with the workforce reductions in 2021.

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.

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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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