# Devon Energy Corp: Form 10-K for the period ended Dec 31, 2022

- Company: [Devon Energy Corp](/companies/dvn.md) (CIK 1090012)
- Form: 10-K
- Filed: 2023-02-15
- Accepted by EDGAR: Feb 15, 2023, 17:01 ET
- Period: 2022-12-31
- Accession: 0000950170-23-002852
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1090012/000095017023002852/dvn-20221231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1090012/000095017023002852/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2022-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2022-01-01 to 2022-12-31 | $19.83bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Income tax | 12 months, 2022-01-01 to 2022-12-31 | $1.74bn | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2022-01-01 to 2022-12-31 | $6.01bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2022-01-01 to 2022-12-31 | $9.12 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2022-01-01 to 2022-12-31 | $9.15 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2022-01-01 to 2022-12-31 | 653,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Capital expenditure | 12 months, 2022-01-01 to 2022-12-31 | $2.54bn | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 3 months, 2022-10-01 to 2022-12-31 | $875.0m | us-gaap:PaymentsOfDividends |
| Dividends paid | 12 months, 2022-01-01 to 2022-12-31 | $3.38bn | us-gaap:PaymentsOfDividends |
| Share repurchases | 12 months, 2022-01-01 to 2022-12-31 | $718.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2022-12-31 | $1.31bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2022-12-31 | $3.89bn | us-gaap:AssetsCurrent |
| Total assets | at 2022-12-31 | $23.72bn | us-gaap:Assets |
| Current liabilities | at 2022-12-31 | $3.10bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2022-12-31 | $6.19bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2022-12-31 | $251.0m | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2022-12-31 | $251.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2022-12-31 | $11.17bn | us-gaap:StockholdersEquity |

## Risk factors

As filed, 45,234 characters.

Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

### Risks Related to Our Industry

### Volatile Oil, Gas and NGL Prices Significantly Impact Our Business

Our financial condition, results of operations and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. Historically, market prices and our realized prices have been volatile. For example, over the last five years, monthly NYMEX WTI oil and NYMEX Henry Hub gas prices ranged from highs of over $120 per Bbl and $9.50 per MMBtu, respectively, to lows of under $30 per Bbl and $1.50 per MMBtu, respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

- the domestic and worldwide supply of and demand for oil, gas and NGLs, including the impact of releases from the U.S. Strategic Petroleum Reserve;
- volatility and trading patterns in the commodity-futures markets;
- climate change incentives and conservation and environmental protection efforts;
- production levels of members of OPEC, Russia, the U.S. or other producing countries;
- geopolitical risks, including the on-going conflict between Russia and Ukraine, as well as other political and civil unrest in the Middle East, Africa, Europe and South America;
- adverse weather conditions, natural disasters, public health crises and other catastrophic events, such as tornadoes, earthquakes, hurricanes and epidemics of infectious diseases;
- regional pricing differentials, including in the Delaware Basin and other areas of our operations;
- differing quality of production, including NGL content of gas produced;
- the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories;
- the price and availability of alternative energy sources;
- technological advances affecting energy consumption and production, including with respect to electric vehicles;
- stockholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas in order to reduce GHG emissions;
- the overall economic environment, including inflationary pressures and rising interest rates;
- changes in trade relations and policies, such as restrictions on oil, gas and NGL exports by the U.S. or economic sanctions, including embargoes, on Russia or other producing countries, as well as the imposition of tariffs by the U.S. or China; and
- other governmental regulations and taxes.

### Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors, including additional development and appraisal activity and the related impact to spacing assumptions for future drilling locations, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. For example, we recognized asset impairments of $2.7 billion in 2020 due to the significant decrease in commodity prices resulting primarily from the COVID-19 pandemic. Consequently, material revisions to our existing reserves estimates may occur as a result of changes in any of these or other factors. Such revisions to proved reserves could have an adverse effect on our financial condition and the value of our properties, as well as the estimates of our future net revenue and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.

### Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production, and Such Activities Are Capital Intensive

The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Moreover, our current development activity is focused on unconventional oil and gas assets, which generally have significantly higher decline rates as compared to conventional assets. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing properties, utilizing secondary or tertiary recovery techniques or acquiring additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Our business requires significant capital to find and acquire new reserves. Although we plan to primarily fund these activities from cash generated by our operations, we have also from time to time relied on other sources of capital, including by accessing the debt and equity capital markets. There can be no assurance that these or other financing sources will be available in the future on acceptable terms, or at all. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, we may be unable to replace our reserves, which would adversely affect our business, financial condition and results of operations.

### Our Operations Are Uncertain and Involve Substantial Costs and Risks

Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:

- unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
- equipment failures or accidents;
- fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
- adverse weather conditions, such as tornadoes, hurricanes, severe thunderstorms and extreme temperatures, the severity and frequency of which could potentially increase as a consequence of climate change;
- other natural disasters, such as earthquakes, floods and wildfires;
- issues with title or in receiving governmental permits or approvals;
- restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
- environmental hazards or liabilities;
- restrictions in access to, or disposal of, water used or produced in drilling and completion operations; and
- shortages or delays in the availability of services or delivery of equipment.

Many of the factors described above have negatively impacted our operations in the past and may do so again in the future. The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events historically have, and in the future could, result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources. For example, we have from time to time experienced well-control events that have resulted in various remediation and clean-up costs and certain of the other impacts described above.

In addition, we rely on our employees, consultants and independent contractors to conduct our operations in compliance with applicable laws and standards. Any violation of such laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial, gender or age discrimination could result in legal claims and reputational harm.

### Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks

We enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we will be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Moreover, many of our contract counterparties have become subject to increasing governmental oversight and regulations in recent years, which could adversely affect the cost and availability of our hedging arrangements.

### We Have Limited Control Over Properties and Investments Operated by Others or through Joint Ventures

Certain of the properties and investments in which we have an interest are operated by other companies and may involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties and investments, including compliance with environmental, health and safety regulations or the amount and timing of required future capital expenditures. In addition, we conduct certain of our operations through joint ventures in which we may share control with third parties, and the other joint venture participants may have interests or goals that are inconsistent with those of the joint venture or us. These limitations and our dependence on such third parties could result in unexpected future costs or liabilities and unplanned changes in operations or future development, which could adversely affect our financial condition and results of operations.

### Midstream Capacity Constraints and Interruptions Impact Commodity Sales

We rely on midstream facilities and systems owned and operated by others to process our gas production and to gather and transport our oil, gas and NGL production to downstream markets. All or a portion of our production in one or more regions may be interrupted or shut in from time to time due to losing access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and natural disasters, terrorism or sabotage, cyberattacks, accidents, field labor issues or strikes. Additionally, midstream operators have in the past been, and in the future may be, subject to constraints that limit their ability to construct, maintain or repair the facilities needed to gather, process and transport our production. Such interruptions or constraints could adversely impact our operations, including by requiring us to curtail our production or obtain alternative takeaway capacity on less favorable terms.

### Competition for Assets, Materials, People and Capital Can Be Significant

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment, services and personnel required to explore, develop and operate properties, such as drilling rigs and oilfield services. The rising costs and scarcity caused by this competitive pressure will generally increase during periods of higher commodity prices and can be further exacerbated by higher inflation rates and supply chain disruptions in the broader economy. For example, we experienced higher operating costs throughout 2022 due to these factors, and we expect such inflationary pressures to continue in 2023. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have resources substantially greater than ours and may have established superior strategic long-term positions and relationships. As a consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing capital and downstream markets. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative energy sources and the application of government regulations.

### Legal, Regulatory and Environmental Risks

### We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business

Our operations are subject to extensive federal, state, tribal and local laws and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. Moreover, certain regulations require the plugging and abandonment of wells, removal of production facilities and other restorative actions by current and former operators, including corporate successors of former operators. We have incurred and will continue to incur substantial capital, operating and remediation costs as a result of these and other laws, regulations, permits and orders to which we are subject.

Changes in public policy have affected, and in the future could further affect, our operations. For example, President Biden and certain members of his administration and Congress have expressed support for, and have taken steps to implement, efforts to transition the economy away from fossil fuels and to promote stricter environmental regulations, and such proposals could impose new and more onerous burdens on our industry and business. The IRA, for instance, contains hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels and carbon capture and sequestration, among other provisions, potentially further accelerating the transition toward lower-or zero-carbon emissions alternatives to fossil fuels. These and other regulatory and public policy developments could, among other things, restrict production levels, delay necessary permitting, impose price controls, change environmental protection requirements, impose restrictions on pipelines or other necessary infrastructure, raise taxes, royalties and other amounts payable to governments or governmental agencies and otherwise increase our operating costs. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to the matters discussed in more detail below.

*Federal Lands –* President Biden and certain members of his administration have expressed support for, and have taken steps to implement, additional regulation of oil and gas leasing and permitting on federal lands. For example, President Biden issued an executive order in January 2021, imposing a near total pause on entering new oil and gas leases on public lands. Although the pause on leasing was subsequently lifted in April 2022, the Department of the Interior issued a report on the federal leasing program in November 2021 that recommended various changes, including, among other things, enhancing bonding requirements and applying a more rigorous land-use planning process prior to leasing. The IRA responded, in part, to the report’s recommendations by increasing onshore royalty rates on all new federal leases. However, certain of the report’s recommendations require further Congressional actions, and we cannot predict to what extent, if any, the Department of the Interior may be able to promulgate rules implementing the remaining recommendations of the November 2021 report. While it is not possible at this time to predict the ultimate impact of these or any other future regulatory changes, any additional restrictions or burdens on our ability to operate on federal lands could adversely impact our business in the Delaware and Powder River Basins, as well as other areas where we operate under federal leases. As of December 31, 2022, less than 20% of our total leasehold resides on federal lands, which is primarily located in the Delaware and Powder River Basins.

*Hydraulic Fracturing –* Various federal agencies have asserted regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA has issued regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and it previously finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Moreover, several state and local governments in areas in which we operate have adopted, or stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as requiring disclosure of chemicals used in hydraulic fracturing, imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. Beyond these regulatory efforts, various policy makers, regulatory agencies and political leaders at the federal, state and local levels have proposed implementing even further restrictions on hydraulic fracturing, including prohibiting the technology outright. Although it is not possible at this time to predict the outcome of these or other proposals, any new restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays or cessation in development or other restrictions on our operations.

*Environmental Laws Generally –* In addition to regulatory efforts focused on hydraulic fracturing, we are subject to various other federal, state, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations or prior operations on assets we have acquired. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. Any such changes could have a significant impact on our operations and profitability.

*Seismic Activity –* Earthquakes in southeastern New Mexico, western Texas, northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the oil and gas industry, particularly the disposal of wastewater in salt-water disposal wells. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. For example, New Mexico implemented protocols in November 2021 requiring operators to take various actions with respect to salt-water disposal wells within a specified proximity of certain seismic activity, including a requirement to limit injection rates if the seismic event is of a certain magnitude. Separately, the Railroad Commission of Texas has shown increasing regulatory focus on seismicity and the oil and gas industry in recent years, and has imposed limits on certain salt-water disposal well activities in portions of the Delaware and Midland Basins. These or similar actions directed at our operating areas could limit the takeaway capacity for produced water in the impacted area, which could increase our operating expense, require us to curtail our development plans or otherwise adversely impact our operations.

*Changes to Tax Laws –* We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate or previously operated, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions and the timing of such deductions, or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. In addition, the IRA includes various changes to the federal tax laws beginning in 2023, including (i) a new 15% corporate alternative minimum tax on “adjusted financial statement income” and (ii) a new 1% excise tax on stock repurchases. While we are still evaluating the full impact of this legislation, and await further guidance and clarifications from the U.S. Treasury, we expect incremental taxes attributable to these new tax provisions.

### Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce GHG emissions, such as carbon dioxide and methane. Policy makers and regulators at both the U.S. federal and state levels have already imposed, or stated intentions to impose, laws and regulations designed to quantify and limit the emission of GHG. For example, the EPA released rule proposals during 2021 and 2022 that if adopted would, among other things, (i) broaden methane and volatile organic compounds emission reduction requirements for certain oil and gas facilities, including a zero-emission standard for pneumatic controllers, and (ii) impose standards to eliminate venting of associated gas, and require capture and sale of gas where sale line is available, at new and existing oil wells. Moreover, the recently enacted IRA imposes a new charge or fee with respect to excess methane emissions from certain petroleum and natural gas facilities starting in 2024 and annually increasing through 2026. In addition to these federal efforts, several states where we operate, including New Mexico, Texas and Wyoming, have already imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas exploration and production activities, including by mandating new leak detection and retrofitting requirements.

Policy makers have also advocated for expanding existing, or creating new, reporting and disclosure requirements regarding GHG emissions and other climate-related matters. For example, the EPA proposed amendments in June 2022 to its Green House Gas Reporting Program, which would, among other things, add well blowouts and other abnormal events as new categories of sources for GHG emissions reporting. In addition, the SEC proposed rules in March 2022 that would require public companies to include extensive climate-related disclosures in their SEC filings. Among other things, the proposed SEC rules, if adopted as written, would mandate disclosures on (i) GHG emissions, including Scope 3 emissions if material or part of a company’s emissions goal, (ii) financial impact and expenditure metrics relating to severe weather and climate change and (iii) a company’s use of scenario analysis and climate targets. Although the SEC has not finalized these rules, we would expect to incur substantial additional compliance costs to the extent these or similar rules are adopted. We further anticipate the costs and other risks associated with any such disclosure requirements to be particularly heightened, given that reporting frameworks on GHG emissions and other climate-related metrics are still maturing and often require the use of numerous assumptions and judgments.

Additionally, public statements with respect to emissions reduction goals, environmental targets or, more broadly, ESG-related goals, are becoming increasingly subject to heightened scrutiny from public and governmental authorities with respect to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks which could, in turn, lead to further negative sentiment against us and our industry.

With respect to more comprehensive regulation, policy makers and political leaders have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade or carbon tax programs. In addition, President Biden has continued to highlight addressing climate change as a priority of his administration, and he previously released an energy plan calling for a number of sweeping changes to address climate change, including, among other measures, a national mobilization effort to achieve net-zero emissions for the U.S. economy by 2050, through increased use of renewable power, stricter fuel-efficiency standards and support for zero-emission vehicles. President Biden issued a number of executive orders in January 2021 with the purpose of implementing certain of these changes, including the rejoining of the Paris Agreement. President Biden subsequently announced a target of reducing economy-wide net GHG emissions in the U.S. by 50% to 52% below 2005 levels by 2030. At the international level, the United States and the European Union jointly announced the launch of a Global Methane Pledge at the 26th Conference of the Parties in 2021, pursuant to which over 130 participating countries have pledged to a collective goal of reducing global methane emissions by at least

30% from 2020 levels by 2030. Although the full impact of these actions is uncertain at this time, the adoption and implementation of these or other initiatives may result in the restriction or cancellation of oil and natural gas activities, greater costs of compliance or consumption (thereby reducing demand for our products) or an impairment in our ability to continue our operations in an economic manner.

In addition to regulatory risk, other market and social initiatives relating to climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing or otherwise encouraging the development and adoption of alternative energy sources and technologies, including by mandating the use of specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, an increasing number of financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could decrease the value of our business and make it more difficult to fund our operations. In addition, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. The increasing attention to climate change may result in further claims or investigations against us, and heightened societal or political pressures may increase the possibility that liability could be imposed on us in such matters without regard to our causation of, or contribution to, the asserted damage or violation, or to other mitigating factors.

Finally, climate change may also result in various enhanced physical risks, such as an increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that may adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we are subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce demand for energy for heating purposes. These and the other risks discussed above could result in additional costs, new restrictions on our operations and reputational harm to us, as well as reduce the actual and forecasted demand for our products. These affects in turn could impair or lower the value of our assets, including by resulting in uneconomic or “stranded” assets, and otherwise adversely impact our profitability, liquidity and financial condition.

### Price Controls, Export Restrictions and Other Governmental Interventions in Energy Markets May Adversely Impact our Business

Domestic and foreign governmental bodies have from time to time intervened in energy markets by imposing price controls, restricting exports, limiting production or otherwise taking actions to impact the availability and price of oil, natural gas and NGLs. For instance, members of the European Union agreed to a price-cap framework in December 2022 for the trading of natural gas in response to rising energy costs in Europe. Similarly, during 2021 and 2022, President Biden authorized several releases from the U.S. Strategic Petroleum Reserve in an effort to lower domestic energy prices. Governments may take similar actions in the future, particularly in the event of disruption in energy markets or national emergency. Any such interventions could adversely impact our business, including by depressing the price of our production and generally introducing greater uncertainty to our operations.

### General and Other Risks Facing our Business

***Our Business Has Been Adversely Impacted by the COVID-19 Pandemic, and We May Experience Continuing or Worsening Adverse Effects From This or Other Pandemics***

The COVID-19 pandemic and related economic repercussions created significant volatility, uncertainty and turmoil in the oil and gas industry and the broader economy. The pandemic and the related responses of governmental authorities and others to limit the spread of the virus significantly reduced global economic activity, which resulted in an unprecedented decline in the demand for oil and other commodities during 2020, along with a corresponding deterioration in commodity prices. Moreover, the COVID-19 pandemic contributed to disruption and volatility in global supply chains that resulted in increased costs and delays for materials, and we and our service providers faced increased potential for business interruption and other operational risks due to changes of business practices and possible constraints in retaining sufficient personnel due to illness, quarantines, government actions or other restrictions in connection with the pandemic. Although commodity prices subsequently recovered after their decline in 2020, COVID-19, its variants or any other future pandemic could lead to similar protracted periods of depressed commodity prices or result in other significant adverse consequences to our business. Further, to the extent COVID-19 or any other pandemic adversely affects our business or the global economic conditions more generally, it may also have the effect of heightening many of the other risks described in this report.

### The Credit Risk of Our Counterparties Could Adversely Affect Us

We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have exposure to financial institutions and insurance companies through our hedging arrangements, our Senior Credit Facility and our insurance policies. Disruptions in the financial markets or otherwise may impact these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into future transactions with us.

In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables. We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-operating partners for their respective share of costs. We also frequently look to buyers of oil and gas properties from us or our predecessors to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties or their successors may experience insolvency, liquidity problems or other issues and may not be able to meet their obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default may result in us being forced to cover the costs of those obligations and liabilities. Our business has been adversely impacted by counterparty defaults in the past, and we may experience similar defaults again in the future.

### Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us

As of December 31, 2022, we had total indebtedness of $6.4 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:

- requiring us to dedicate a portion of our liquidity to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;
- increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and
- limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.

In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned asset sales and purchases, liquidity, size and scale of our production and commodity prices. Certain of our contractual obligations require us to provide letters of credit or other assurances. Any credit downgrades could adversely impact our ability to access financing and trade credit, require us to provide additional letters of credit or other assurances under contractual arrangements and increase our interest rate under the Senior Credit Facility as well as the cost of any other future debt.

### Cyberattacks May Adversely Impact Our Operations

Our business has become increasingly dependent on digital technologies, and we anticipate expanding the use of these technologies in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with the growing dependence on technology is a greater sensitivity to cyberattack related activities, which have increasingly targeted our industry. Perpetrators of cyberattacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating confidential and proprietary information, intellectual property or financial assets, corrupting data or causing operational disruptions as well as preventing users from accessing systems or information for the purpose of demanding payment in order for users to regain access. In addition, our vendors (including third-party cloud and IT service providers), midstream providers and other business partners may separately suffer disruptions or breaches from cyberattacks, which, in turn, could adversely impact our operations and compromise our information. Moreover, we and other upstream companies rely on extensive oil and gas infrastructure and distribution systems to deliver our production to market, which in turn depend upon digital technologies. Any cyberattack directed at such infrastructure or systems could adversely impact our business and operations, including by limiting our ability to transport and market our production. Geopolitical instability may also increase our cybersecurity risk.

Although we have experienced cybersecurity incidents from time to time, none have had a material effect on our business, operations or reputation. However, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future due to system vulnerabilities, human error or malfeasance or other factors. Any such attacks could have an adverse impact on our business, operations or reputation and lead to remediation costs, litigation or regulatory actions. Moreover, as the sophistication and volume of cyberattacks continue to increase, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities, and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.

### Insurance Does Not Cover All Risks

As discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development and production of oil, gas and NGLs. To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, we have limited or no insurance coverage for a variety of other risks, including pollution events that are considered gradual, war and political risks and fines or penalties assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have an adverse effect on our profitability, financial condition and liquidity.

### Our Business Could Be Adversely Impacted by Shareholder Activism, Proxy Contests or Similar Actions

In recent years, proxy contests and other forms of shareholder activism have been directed against numerous public companies. Investors may from time to time seek to involve themselves in the governance, strategic direction and operations of the Company, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. These actions may be prompted or exacerbated by unfavorable recommendations or ratings from proxy advisory firms or other third parties, including with respect to our performance (or the perception of our performance) under ESG metrics. Such actions could adversely impact our business by distracting our Board of Directors and employees from our long-term strategy, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on core business operations and strategic transactions or plans and provoking perceived uncertainty about the future direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our common stock.

### Our Acquisition and Divestiture Activities Involve Substantial Risks

Our business depends, in part, on making acquisitions, including by merger and other similar transactions, that complement or expand our current business and successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:

- mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;
- difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
- unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.

In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or business and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.

### Our Ability to Declare and Pay Dividends and Repurchase Shares Is Subject to Certain Considerations

Dividends, whether fixed or variable, and share repurchases are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including the Company’s financial results, cash requirements and future prospects, as well as such other factors deemed relevant by our Board of Directors. We can provide no assurance that we will continue to pay dividends or execute share repurchases at the current rate or at all. Any elimination of, or downward revision in, our dividend payout or share repurchase program could have an adverse effect on the market price of our common stock.

## Legal proceedings

As filed, 1,251 characters.

We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report and subject to the matters noted below, there were no material pending legal proceedings to which we are a party or to which any of our property is subject. For more information on our legal contingencies, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.

On April 7, 2020, WPX Energy, Inc., a wholly-owned subsidiary of the Company, received a notice of violation from the EPA relating to specific historical air emission events occurring on the Fort Berthold Indian Reservation in North Dakota. On July 22, 2022, we received an updated notice of violation from the EPA relating to the same underlying events. On June 4, 2021, we received a separate notice of violation from the EPA relating to alleged air permit violations by WPX Energy Permian, LLC, a wholly-owned subsidiary of the Company, during 2020 in western Texas. The Company has been engaging with the EPA to resolve each of these matters. Although these matters are ongoing and management cannot predict their ultimate outcome, the resolution of each of these matters may result in a fine or penalty in excess of $300,000.

## Management's discussion and analysis

As filed, 61,963 characters.

### Introduction

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

The following discussion and analyses primarily focus on 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2021 Annual Report on Form 10-K.

### Executive Overview

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

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

- Generated $8.5 billion of operating cash flow in 2022, which is a 74% increase from the prior year.
- 2022 oil production averaged 299 MBbls/d, which is a 3% increase from the prior year.
- As of December 31, 2022, completed approximately 65% of our authorized $2.0 billion share repurchase program, with 25.7 million of our common shares repurchased for $1.3 billion, or $50.90 per share, since inception of the plan.
- Exited 2022 with $4.5 billion of liquidity, including $1.5 billion of cash.
- Including variable dividends, paid dividends of approximately $3.4 billion in 2022 and have declared $579 million of dividends to be paid in the first quarter of 2023, which is inclusive of an 11% increase to our fixed quarterly dividend to $0.20 per share.
- Invested approximately $100 million in emissions reduction capital projects in 2022.

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

Commodity prices strengthened in 2021 and continued to strengthen throughout the majority of 2022, which has significantly improved our earnings and cash flow generation. The increase in commodity prices was primarily driven by increased demand resulting from the recovery from the COVID-19 pandemic. The military conflict between Russia and Ukraine and related economic sanctions imposed on Russia, as well as OPEC+ restraining production growth, further exacerbated supply shortages, causing oil prices to increase even more throughout most of 2022. However, oil prices did begin to decline in the fourth quarter of 2022 due to economic uncertainty surrounding inflation and increased interest rates as well as certain geopolitical events.

As presented in the graph at the left, commodity prices are volatile and heavily influence our financial performance and trends. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub gas prices ranged from average highs of $94.39 per Bbl and $6.65 per MMBtu, respectively, to average lows of $39.59 per Bbl and $2.08 per MMBtu, respectively.

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

Our earnings in 2020 were negatively impacted by lower commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. Earnings improved significantly in 2021 due to commodity prices recovering from the initial COVID-19 pandemic as well as the Merger closing in January 2021. Earnings continued to improve during 2022 as commodity prices continued to strengthen and we executed on our strategic priorities as a company. Led by a 73% and 39% increase in Henry Hub and WTI from 2021 to 2022, respectively, our unhedged combined realized price rose 38%. Additionally, volumes increased 7% from 2021 to 2022 primarily due to the continued development of assets in the Delaware Basin and acquisitions in the Williston Basin and Eagle Ford that both closed in the third quarter of 2022.

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

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

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

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

### Business and Industry Outlook

In 2022, Devon marked its 51st anniversary in the oil and gas business and its 34th year as a public company. The strength of our portfolio of assets, the success of our 2021 transformational merger with WPX and strong commodity prices led us to generate net earnings of $6 billion in 2022, which was more than double that of 2021. Our portfolio was further strengthened in 2022 following the completion of two bolt-on acquisitions in the Williston Basin and Eagle Ford that were highly complementary to our existing positions in each basin. Both acquisitions were funded with cash on hand, and our balance sheet and financial position remains strong following the acquisitions. We remain committed to continuing our track record of industry leading return of capital to our shareholders, underpinned by low capital reinvestment rates and a disciplined, returns-driven strategy which is designed to be successful through economic cycles. In line with this strategy, we returned over $4 billion of cash to shareholders through fixed and variable cash dividends and share repurchases in 2022.

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

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

### Results of Operations

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

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

### Production Volumes

| Oil (MBbls/d) | 2022 | % of Total | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 210 | 70% | 197 | 7% |
| Anadarko Basin | 14 | 5% | 15 | -3% |
| Williston Basin | 33 | 11% | 41 | -20% |
| Eagle Ford | 24 | 8% | 18 | 33% |
| Powder River Basin | 14 | 5% | 15 | -10% |
| Other | 4 | 1% | 4 | -5% |
| Total | 299 | 100% | 290 | 3% |

| Gas (MMcf/d) | 2022 | % of Total | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 607 | 62% | 535 | 13% |
| Anadarko Basin | 221 | 23% | 217 | 2% |
| Williston Basin | 61 | 6% | 58 | 4% |
| Eagle Ford | 67 | 7% | 58 | 15% |
| Powder River Basin | 19 | 2% | 20 | -6% |
| Other | 1 | 0% | 2 | -50% |
| Total | 976 | 100% | 890 | 10% |

| NGLs (MBbls/d) | 2022 | % of Total | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 103 | 69% | 87 | 18% |
| Anadarko Basin | 25 | 17% | 24 | 5% |
| Williston Basin | 9 | 6% | 9 | -5% |
| Eagle Ford | 10 | 6% | 9 | 11% |
| Powder River Basin | 2 | 2% | 3 | -9% |
| Other | — | 0% | 1 | N/M |
| Total | 149 | 100% | 133 | 12% |

| Combined (MBoe/d) | 2022 | % of Total | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 414 | 68% | 374 | 11% |
| Anadarko Basin | 76 | 13% | 75 | 1% |
| Williston Basin | 51 | 8% | 60 | -14% |
| Eagle Ford | 45 | 7% | 37 | 23% |
| Powder River Basin | 19 | 3% | 21 | -9% |
| Other | 5 | 1% | 5 | -1% |
| Total | 610 | 100% | 572 | 7% |

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

### Realized Prices

| Oil (per Bbl) | 2022 | Realization | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| WTI index | $94.39 |  | $67.86 | 39% |
| Realized price, unhedged | $94.11 | 100% | $65.98 | 43% |
| Cash settlements | $(9.38) |  | $(11.60) |  |
| Realized price, with hedges | $84.73 | 90% | $54.38 | 56% |

31

#### Index to Financial Statements

| Gas (per Mcf) | 2022 | Realization | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Henry Hub index | $6.65 |  | $3.85 | 73% |
| Realized price, unhedged | $5.47 | 82% | $3.40 | 61% |
| Cash settlements | $(0.93) |  | $(0.66) |  |
| Realized price, with hedges | $4.54 | 68% | $2.74 | 66% |

| NGLs (per Bbl) | 2022 | Realization | 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| WTI index | $94.39 |  | $67.86 | 39% |
| Realized price, unhedged | $34.18 | 36% | $29.52 | 16% |
| Cash settlements | $— |  | $(0.38) |  |
| Realized price, with hedges | $34.18 | 36% | $29.14 | 17% |

| Combined (per Boe) | 2022 | 2021 | Change |
| --- | ---: | ---: | ---: |
| Realized price, unhedged | $63.20 | $45.68 | 38% |
| Cash settlements | $(6.08) | $(7.01) |  |
| Realized price, with hedges | $57.12 | $38.67 | 48% |

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

### Hedge Settlements

|  | 2022 Q | 2021 | Change |
| --- | ---: | ---: | ---: |
| Oil | $(1,025) | $(1,230) | 17% |
| Natural gas | (331) | (213) | -55% |
| NGL | — | (19) | 100% |
| Total cash settlements (1) | $(1,356) | $(1,462) | 7% |

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

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

### Production Expenses

|  | 2022 | 2021 | Change |
| --- | ---: | ---: | ---: |
| LOE | $1,071 | $859 | 25% |
| Gathering, processing & transportation | 693 | 606 | 14% |
| Production taxes | 954 | 633 | 51% |
| Property taxes | 79 | 33 | 139% |
| Total | $2,797 | $2,131 | 31% |
| Per Boe: |  |  |  |
| LOE | $4.81 | $4.12 | 17% |
| Gathering, processing & transportation | $3.11 | $2.91 | 7% |
| Percent of oil, gas and NGL sales: |  |  |  |
| Production taxes | 6.8% | 6.6% | 2% |

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

### 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.

| Field-level cash margin (Non-GAAP) | 2022 | $ per BOE | 2021 | $ per BOE |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | $8,074 | $53.39 | $5,183 | $37.98 |
| Anadarko Basin | 968 | $35.00 | 616 | $22.46 |
| Williston Basin | 867 | $46.28 | 759 | $34.79 |
| Eagle Ford | 870 | $52.68 | 474 | $35.33 |
| Powder River Basin | 401 | $57.39 | 290 | $37.83 |
| Other | 105 | $62.58 | 78 | $42.00 |
| Total | $11,285 | $50.65 | $7,400 | $35.47 |

### DD&A

|  | 2022 | 2021 | Change |
| --- | ---: | ---: | ---: |
| Oil and gas per Boe | $9.52 | $9.83 | -3% |
| Oil and gas | $2,119 | $2,050 | 3% |
| Other property and equipment | 104 | 108 | -4% |
| Total | $2,223 | $2,158 | 3% |

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

### General and Administrative Expense

|  | 2022 | 2021 | Change |
| --- | ---: | ---: | ---: |
| G&A per Boe | $1.77 | $1.88 | -6% |
| Labor and benefits | $229 | $255 | -10% |
| Non-labor | 166 | 136 | 22% |
| Total | $395 | $391 | 1% |

### Other Items

|  | 2022 | 2021 | Change in earnings |
| --- | ---: | ---: | ---: |
| Commodity hedge valuation changes (1) | $698 | $(82) | $780 |
| Marketing and midstream operations | (35) | (19) | (16) |
| Exploration expenses | 29 | 14 | (15) |
| Asset dispositions | (44) | (168) | (124) |
| Net financing costs | 309 | 329 | 20 |
| Restructuring and transaction costs | — | 258 | 258 |
| Other, net | (95) | (43) | 52 |
|  |  |  | $955 |

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

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

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

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

### Income Taxes

|  | 2022 | 2021 |
| --- | ---: | ---: |
| Current expense | $559 | $16 |
| Deferred expense | 1,179 | 49 |
| Total expense | $1,738 | $65 |
| Current tax rate | 7% | 0% |
| Deferred tax rate | 15% | 2% |
| Effective income tax rate | 22% | 2% |

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

### 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.

|  | Year Ended December 31, 2022 | 2021 |
| --- | ---: | ---: |
| Operating cash flow | $8,530 | $4,899 |
| WPX acquired cash | — | 344 |
| Acquisitions of property and equipment | (2,583) | (18) |
| Divestitures of property and equipment | 39 | 79 |
| Capital expenditures | (2,542) | (1,989) |
| Investment activity, net | (37) | 10 |
| Debt activity, net | — | (1,302) |
| Repurchases of common stock | (718) | (589) |
| Common stock dividends | (3,379) | (1,315) |
| Noncontrolling interest activity, net | (30) | (41) |
| Other | (97) | (44) |
| Net change in cash, cash equivalents and restricted cash | $(817) | $34 |
| Cash, cash equivalents and restricted cash at end of period | $1,454 | $2,271 |

#### Operating Cash Flow and WPX Acquired Cash

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

#### Acquisitions of Property and Equipment

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

#### Divestitures of Property and Equipment

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

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

#### Capital Expenditures

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

|  | Year Ended December 31, 2022 | 2021 |
| --- | ---: | ---: |
| Delaware Basin | $1,678 | $1,535 |
| Anadarko Basin | 157 | 53 |
| Williston Basin | 158 | 77 |
| Eagle Ford | 229 | 122 |
| Powder River Basin | 149 | 73 |
| Other | 9 | 3 |
| Total oil and gas | 2,380 | 1,863 |
| Midstream | 92 | 64 |
| Other | 70 | 62 |
| Total capital expenditures | $2,542 | $1,989 |

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

#### Investment Activity

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

#### Debt Activity

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

#### Repurchases of Common Stock and Shareholder Distributions

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

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

| 2022: | Fixed | Variable | Total | Rate Per Share |
| --- | ---: | ---: | ---: | ---: |
| First quarter | $109 | $558 | $667 | $1.00 |
| Second quarter | 105 | 725 | 830 | $1.27 |
| Third quarter | 117 | 890 | 1,007 | $1.55 |
| Fourth quarter | 117 | 758 | 875 | $1.35 |
| Total year-to-date | $448 | $2,931 | $3,379 |  |
| 2021: |  |  |  |  |
| First quarter | $76 | $127 | $203 | $0.30 |
| Second quarter | 75 | 154 | 229 | $0.34 |
| Third quarter | 74 | 255 | 329 | $0.49 |
| Fourth quarter | 73 | 481 | 554 | $0.84 |
| Total year-to-date | $298 | $1,017 | $1,315 |  |

#### Noncontrolling Interest Activity

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

### Liquidity

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

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

#### Operating Cash Flow

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

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

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

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

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

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

#### Credit Availability

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

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

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

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

#### Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and size and scale of our production. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa2 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

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

#### Fixed Plus Variable Dividend

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

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

#### Share Repurchase Program

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

#### Capital Expenditures

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

#### Contractual Obligations

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

### Contingencies and Legal Matters

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

### Critical Accounting Estimates

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

### Oil and Gas Assets Accounting, Classification, Reserves & Valuation

#### Successful Efforts Method of Accounting and Classification

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

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

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

#### Reserves

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

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

#### Valuation of Long-Lived Assets

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

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

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

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

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

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

### Income Taxes

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

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

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

### Purchase Accounting

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

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

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

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

### Non-GAAP Measures

### Core Earnings

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

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

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

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

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

| 2022 | Year Ended December 31, Before Tax | After Tax | After NCI | Per Diluted Share |
| --- | ---: | ---: | ---: | ---: |
| Earnings attributable to Devon (GAAP) | $7,775 | $6,037 | $6,015 | $9.12 |
| Adjustments: |  |  |  |  |
| Asset dispositions | (44) | (34) | (34) | (0.05) |
| Asset and exploration impairments | 13 | 10 | 10 | 0.02 |
| Deferred tax asset valuation allowance | — | 17 | 17 | 0.03 |
| Fair value changes in financial instruments | (690) | (532) | (532) | (0.81) |
| Core earnings attributable to Devon (Non-GAAP) | $7,054 | $5,498 | $5,476 | $8.31 |
| **2021** |  |  |  |  |
| Earnings attributable to Devon (GAAP) | $2,898 | $2,833 | $2,813 | $4.19 |
| Adjustments: |  |  |  |  |
| Asset dispositions | (168) | (129) | (129) | (0.19) |
| Asset and exploration impairments | 6 | 5 | 5 | 0.01 |
| Deferred tax asset valuation allowance | — | (639) | (639) | (0.95) |
| Change in tax legislation | — | 60 | 60 | 0.09 |
| Fair value changes in financial instruments | 82 | 63 | 63 | 0.09 |
| Restructuring and transaction costs | 258 | 224 | 224 | 0.33 |
| Early retirement of debt | (30) | (23) | (23) | (0.04) |
| Core earnings attributable to Devon (Non-GAAP) | $3,046 | $2,394 | $2,374 | $3.53 |

43

#### Index to Financial Statements

| 2020 Continuing Operations | Year ended December 31, Before Tax | After Tax | After NCI | Per Diluted Share |
| --- | ---: | ---: | ---: | ---: |
| Loss attributable to Devon (GAAP) | $(3,090) | $(2,543) | $(2,552) | $(6.78) |
| Adjustments: |  |  |  |  |
| Asset dispositions | (1) | — | — | — |
| Asset and exploration impairments | 2,847 | 2,207 | 2,207 | 5.87 |
| Deferred tax asset valuation allowance | — | 230 | 230 | 0.60 |
| Fair value changes in financial instruments | 161 | 125 | 125 | 0.32 |
| Change in tax legislation | — | (113) | (113) | (0.29) |
| Restructuring and transaction costs | 49 | 38 | 38 | 0.10 |
| Core loss attributable to Devon (Non-GAAP) | $(34) | $(56) | $(65) | $(0.18) |
| **Discontinued Operations** |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(152) | $(128) | $(128) | $(0.34) |
| Adjustments: |  |  |  |  |
| Asset dispositions | 1 | 19 | 19 | 0.05 |
| Asset impairments | 182 | 143 | 143 | 0.37 |
| Fair value changes in foreign currency and other | (8) | (5) | (5) | (0.01) |
| Restructuring and transaction costs | 9 | 6 | 6 | 0.02 |
| Core earnings attributable to Devon (Non-GAAP) | $32 | $35 | $35 | $0.09 |
| **Total** |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(3,242) | $(2,671) | $(2,680) | $(7.12) |
| Adjustments: |  |  |  |  |
| Continuing Operations | 3,056 | 2,487 | 2,487 | 6.60 |
| Discontinued Operations | 184 | 163 | 163 | 0.43 |
| Core loss attributable to Devon (Non-GAAP) | $(2) | $(21) | $(30) | $(0.09) |

### 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.

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

|  | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| **Net earnings (GAAP)** | $6,037 | $2,833 | $(2,671) |
| Net loss from discontinued operations, net of tax | — | — | 128 |
| Financing costs, net | 309 | 329 | 270 |
| Income tax expense (benefit) | 1,738 | 65 | (547) |
| Exploration expenses | 29 | 14 | 167 |
| Depreciation, depletion and amortization | 2,223 | 2,158 | 1,300 |
| Asset impairments | — | — | 2,693 |
| Asset dispositions | (44) | (168) | (1) |
| Share-based compensation | 87 | 77 | 76 |
| Derivative and financial instrument non-cash valuation changes | (698) | 82 | 161 |
| Restructuring and transaction costs | — | 258 | 49 |
| Accretion on discounted liabilities and other | (95) | (43) | (34) |
| **EBITDAX (Non-GAAP)** | 9,586 | 5,605 | 1,591 |
| Marketing and midstream revenues and expenses, net | 35 | 19 | 35 |
| Commodity derivative cash settlements | 1,356 | 1,462 | (316) |
| General and administrative expenses, cash-based | 308 | 314 | 262 |
| **Field-level cash margin (Non-GAAP)** | $11,285 | $7,400 | $1,572 |

45

## Market risk

As filed, 1,927 characters.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

### Commodity Price Risk

Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our gas and NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we systematically hedge a portion of our production through various financial transactions. The key terms to our oil and gas derivative financial instruments as of December 31, 2022 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2022, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $150 million.

### Interest Rate Risk

At December 31, 2022, we had total debt of $6.4 billion. All of our debt is based on fixed interest rates averaging 5.8%.

### Foreign Currency Risk

We had no material foreign currency risk at December 31, 2022.

## Controls and procedures

As filed, 2,458 characters.

### Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2022 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

### Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in *Internal Control – Integrated Framework* issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, which was completed on February 15, 2023, management concluded that its internal control over financial reporting was effective as of December 31, 2022.

The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2022, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” of this report.

### Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Filed Feb 15, 2023.
Source: SEC EDGAR, the filing index for accession 0000950170-23-002852. Last ingested by Listed: Oct 24, 2026, 15:02 ET. No prices; not investment advice.