DEVON ENERGY CORP/DE (DVN) FY 2023 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 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 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 2022 Annual Report on Form 10-K.

Executive Overview

We are a leading independent oil and natural gas exploration and production company whose operations are focused onshore in the United States. Our operations are currently focused in five core areas: the Delaware Basin, Eagle Ford, Anadarko Basin, Williston Basin and Powder River Basin. Our asset base is underpinned by premium acreage in the economic core of the Delaware Basin and our diverse, top-tier resource plays provide a deep inventory of opportunities for years to come. In the third quarter of 2022, we acquired additional producing properties and leasehold interests in both the Williston Basin and Eagle Ford that were complementary to our existing acreage, offered operational synergies and added additional high-quality inventory to our portfolio. Moving forward into 2024, we plan to refine our capital allocation by further concentrating investment in the Delaware Basin. By shifting more capital to the core of this world-class basin and high-grading activity across the rest of our diversified portfolio, we anticipate delivering meaningful improvements to our capital efficiency which will position us to generate growth in free cash flow which can be returned to shareholders.

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 recent performance highlights for these priorities include the following items for 2023:

•
Oil production totaled 320 MBbls/d, which is a 7% increase year over year.

•
Through 2023, completed approximately 77% of our authorized $3.0 billion share repurchase program, with approximately 45 million of our common shares repurchased for approximately $2.3 billion, or $51.05 per share, since inception of the plan.

•
Retired $242 million of senior notes.

•
Exited with $3.9 billion of liquidity, including $0.9 billion of cash.

•
Generated $6.5 billion of operating cash flow.

•
Including variable dividends, paid dividends of approximately $1.9 billion.

•
Earnings attributable to Devon were $3.7 billion, or $5.84 per diluted share.

•
Core earnings (Non-GAAP) were $3.7 billion, or $5.71 per diluted share.

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 inflation and geopolitical events. Our cash-return objectives remain focused on opportunistic share repurchases, funding our fixed and variable dividends, repaying debt at upcoming maturities and building cash balances.

Our net earnings and operating cash flow are highly dependent upon oil, gas and NGL prices which can be incredibly volatile due to several varying factors. Commodity prices strengthened during 2022 as the continued recovery from the COVID-19 pandemic increased demand for oil and gas commodities, while economic sanctions imposed on Russia and restraint from OPEC+ on production

28

Table of Contents

Index to Financial Statements

growth both simultaneously impacted the supply of these commodities. In 2023, commodity prices weakened primarily due to economic uncertainty surrounding inflation and increased interest rates as well as certain geopolitical events. The graphs below show the trends in commodity prices over the past three years and their related impact on our net earnings, operating cash flow and capital investments.

As we dependably generate strong cash flow results as shown above, we will continue to prioritize delivering cash returns to shareholders through share repurchases and our fixed plus variable dividend strategy while maintaining a strong liquidity position. Since the inception of our authorized $3.0 billion share repurchase program, we have repurchased approximately 45 million common shares for approximately $2.3 billion, or $51.05 per share. We also returned value to shareholders by paying dividends of approximately $1.9 billion during 2023. We exited 2023 with $3.9 billion of liquidity, comprised of $0.9 billion of cash and $3.0 billion of available credit under our 2023 Senior Credit Facility. We currently have $6.2 billion of debt outstanding, of which approximately $483 million is classified as short-term. Additionally, to help mitigate the volatility of commodity prices and protect ourselves from downside risk, we currently have approximately 30% and 20% of our anticipated 2024 oil and gas production hedged, respectively.

29

Table of Contents

Index to Financial Statements

Business and Industry Outlook

In 2023, Devon marked its 52nd anniversary in the oil and gas business and its 35th year as a public company. We generated nearly $6.5 billion of operating cash flow in 2023 as a result of the strength of our portfolio of assets and our operational execution. Our portfolio benefited from highly complementary assets that were acquired in 2022. Our 2023 operating cash flow was materially lower than 2022 as commodity prices declined from 2022 highs and cost inflation increased in 2023.

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 economic cycles. In line with this strategy, we returned $2.8 billion of cash to shareholders through fixed and variable cash dividends and share repurchases in 2023. For 2024, we are targeting approximately 70% of our free cash flow to be returned to shareholders through cash dividends and share repurchases.

In 2023, WTI oil prices averaged $77.62 per Bbl versus $94.39 per Bbl in 2022, reflecting a downward trend as oil prices remained volatile even with continued capital discipline by global oil producers. The market price for crude oil is currently expected to be lower in 2024 due to concerns of a global economic slowdown driven by high interest rates and high inflation that could weaken economic activity and oil demand. Additionally, oil 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. Growing supply from U.S. oil producers could also weigh down prices in 2024 by dampening the impact of OPEC+ supply cuts. Henry Hub natural gas prices fell in 2023, averaging $2.74 per Mcf compared to $6.65 per Mcf in 2022. For 2024, natural gas prices are expected to remain consistent with 2023 prices due to high storage levels from an abundance of supply and milder winter weather, weakening economic conditions in some sectors leading to lower demand, and continued alternative energy diversification. Our 2024 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 30% of our anticipated oil volumes and 20% of our anticipated gas volumes. In order to further insulate our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges to protect price realizations across our portfolio.

Our commitment to capital discipline and capital efficiency remains unchanged with our 2024 capital program. Similar to 2023, the majority of our 2024 capital, or approximately 60%, is expected to be focused on our highest returning oil play, the Delaware Basin. The remainder of our 2024 capital will continue to be deployed to our other core areas of Eagle Ford, Williston Basin, Anadarko Basin and Powder River Basin but with a reduced activity level in some of these areas, particularly the Williston Basin. Our 2024 capital is expected to be approximately 10% lower than 2023 due to this activity reduction and due to other identified cost reductions. Our capital efficiency is expected to improve as lower 2024 capital offsets the impact of lower oil production from reduced 2024 activity. Due to our strategy of spending within cash flow, we expect to continue generating material amounts of free cash flow for 2024.

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 2023 net earnings were $3.8 billion, compared to net earnings of $6.0 billion for 2022. The graph below shows the change in net earnings from 2022 to 2023. The material changes are further discussed by category on the following pages.

30

Table of Contents

Index to Financial Statements

Production Volumes

From 2022 to 2023, the change in volumes contributed to a $1.0 billion increase in earnings. The increase in volumes was primarily due to an acquisition in the Eagle Ford, which closed in the third quarter of 2022, as well as continued development in the Delaware Basin and Anadarko Basin.

31

Table of Contents

Index to Financial Statements

Realized Prices

From 2022 to 2023, realized prices contributed to a $4.3 billion decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. The decrease 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.

32

Table of Contents

Index to Financial Statements

Production Expenses

LOE expenses and LOE per BOE increased primarily due to acquisitions in the Eagle Ford and Williston Basin that both closed in the third quarter of 2022, along with inflation and higher volumes resulting from increased activity in the Delaware Basin and Anadarko Basin. This is partially offset by decreased production taxes due to lower 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

DD&A and our oil and gas per BOE rate both increased in 2023 primarily due to acquisitions in the Eagle Ford and Williston Basin which both closed in the third quarter of 2022. Increased activity in the Delaware Basin and Anadarko Basin also led to an increase in DD&A.

General and Administrative Expense

33

Table of Contents

Index to Financial Statements

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.

In 2023, asset dispositions include a $64 million gain related to the difference between the fair value and the book value of assets contributed to the Water JV, which was partially offset by a $33 million loss related to the re-valuation of contingent earnout payments associated with divested Barnett assets. In 2022, asset dispositions include a $42 million gain related to the re-valuation of contingent earnout payments associated with divested Barnett Shale assets. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

For discussion on other, net, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Income Taxes

For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report. Our 2023 current rate is below the 15% stated rate in the CAMT due to utilization of tax credits and favorable AFSI adjustments, including depreciation and other items. While our 2023 current income tax rate was 10%, we expect our 2024 income tax rate could approach the mid-teens, depending on commodity prices among other factors.

34

Table of Contents

Index to Financial Statements

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

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 funded all of our capital expenditures, and we continued to return value to our shareholders by utilizing cash flow and cash balances for dividends, share repurchases and debt repayments.

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 2023 represent approximately 60% of our operating cash flow.

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.

35

Table of Contents

Index to Financial Statements

Divestitures of Property and Equipment

During 2023 and 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.

Investment Activity

During 2023 and 2022, Devon received distributions from our investments of $32 million and $39 million, respectively. Devon contributed $53 million and $76 million to our investments during 2023 and 2022, respectively.

Debt Activity

During 2023, we repaid $242 million of senior notes at maturity.

Shareholder Distributions and Stock Activity

We repurchased 19.1 million shares of common stock for $979 million in 2023 and 11.7 million shares of common stock for $718 million in 2022 under the share repurchase program authorized by our Board of Directors. For additional information, see Note 17 in “Item 8. Financial Statements and Supplementary Data” in this report.

The following table summarizes our common stock dividends in 2023 and 2022. Devon has raised its fixed dividend multiple times over the past two calendar years to $0.20 per share beginning in the first quarter of 2023. In addition to the fixed quarterly dividend, we paid a variable dividend in each quarter of 2023 and 2022. For additional information, see Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report.

Noncontrolling Interest Activity

During 2023, we received $37 million of contributions from our noncontrolling interests in CDM. During 2023 and 2022, we distributed $45 million and $30 million, respectively, 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.

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

36

Table of Contents

Index to Financial Statements

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 2023, we held approximately $900 million 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, 2023 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, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2024. The currently elevated level of cost inflation has eroded, and could continue to erode, our cost efficiencies gained over previous years and pressure our margin in 2024. 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. 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, joint interest owners 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 2023 Senior Credit Facility at December 31, 2023. The 2023 Senior Credit Facility matures on March 24, 2028, with the option to extend the maturity date by three additional one-year periods subject to lender consent. The 2023 Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2023, there were no borrowings under our commercial paper program. See Note 13 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The 2023 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, 2023, we were in compliance with this covenant with a 22% debt-to-capitalization ratio.

Our access to funds from the 2023 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 2023 Senior Credit Facility is not conditioned on the absence of a material adverse effect.

37

Table of Contents

Index to Financial Statements

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 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.

Cash Returns to Shareholders

We are committed to returning approximately 70% of our free cash flow to shareholders through a fixed dividend, variable dividend and share repurchases. 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 addition to the fixed quarterly dividend, we may pay a variable dividend or complete share repurchases. Each quarter’s free cash flow, which is a non-GAAP measure, is computed as operating cash flow (a GAAP measure) before balance sheet changes less capital expenditures. 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 2024, Devon raised its fixed dividend by 10%, to $0.22 per share, and announced a cash dividend in the amount of $0.44 per share payable in the first quarter of 2024. The dividend consists of a fixed quarterly dividend in the amount of approximately $140 million (or $0.22 per share) and a variable dividend in the amount of approximately $140 million (or $0.22 per share).

Our Board of Directors has authorized a $3.0 billion share repurchase program that expires on December 31, 2024. Through February 23, 2024, we had executed $2.4 billion of the authorized program.

Capital Expenditures

Our 2024 capital expenditure budget is expected to be approximately $3.3 billion to $3.6 billion, which is approximately 10% lower than our 2023 capital expenditures. In 2024, we plan to refine our capital allocation by further concentrating investment in the Delaware Basin.

Contractual Obligations

As of December 31, 2023, 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 5, 7, 13, 14, 15 and 18 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

In February 2024, Devon committed to invest approximately $90 million in a geothermal technology company and expects to fund the commitment throughout 2024.

38

Table of Contents

Index to Financial Statements

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 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.

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, 2023, all material 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, 2023, Devon had approximately $501 million of undeveloped leasehold costs. Of the remaining undeveloped leasehold costs at December 31, 2023, none is scheduled to expire in 2024.

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 2023, 90% 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 3% 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

39

Table of Contents

Index to Financial Statements

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 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.

None of our oil and gas assets were at risk of impairment as of December 31, 2023.

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.

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 percent 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 2023 for Devon, but the Merger did cause an ownership change for WPX.

40

Table of Contents

Index to Financial Statements

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% CAMT and several new and expanded clean energy credits and incentives. The CAMT will be assessed on applicable corporations with an average annual AFSI that exceeds $1 billion for the preceding three consecutive years. We have made an accounting policy election to not consider the effects of the CAMT on the realizability of our deferred tax assets, carryforwards and other tax credits and will instead account for any such effects as a period cost when they arise. We believe we are subject to the CAMT as we had an average annual AFSI that exceeded $1 billion for the three-year period ended December 31, 2022. Incremental taxes attributable to the CAMT are possible and such taxes may be significant.

Non-GAAP Measures

Core Earnings

We make reference to “core earnings attributable to Devon” and “core earnings per share attributable to Devon” in “Overview of 2023 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 attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our quarterly financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2023 and 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.

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.

41

Table of Contents

Index to Financial Statements

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

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 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 operations.

42

Table of Contents

Index to Financial Statements

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

43

Table of Contents

Index to Financial Statements