# Devon Energy Corp: Form 10-K for the period ended Dec 31, 2021

- Company: [Devon Energy Corp](/companies/dvn.md) (CIK 1090012)
- Form: 10-K
- Filed: 2022-02-16
- Accepted by EDGAR: Feb 16, 2022, 12:02 ET
- Period: 2021-12-31
- Accession: 0001564590-22-005321
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1090012/000156459022005321/dvn-10k_20211231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1090012/000156459022005321/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2021-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2021-01-01 to 2021-12-31 | $13.75bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Income tax | 12 months, 2021-01-01 to 2021-12-31 | $65.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2021-01-01 to 2021-12-31 | $2.81bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2021-01-01 to 2021-12-31 | $4.19 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2021-01-01 to 2021-12-31 | $4.20 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2021-01-01 to 2021-12-31 | 665,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Capital expenditure | 12 months, 2021-01-01 to 2021-12-31 | $1.99bn | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 3 months, 2021-10-01 to 2021-12-31 | $554.0m | us-gaap:PaymentsOfDividends |
| Dividends paid | 12 months, 2021-01-01 to 2021-12-31 | $1.31bn | us-gaap:PaymentsOfDividends |
| Share repurchases | 12 months, 2021-01-01 to 2021-12-31 | $589.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2021-12-31 | $2.10bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2021-12-31 | $4.25bn | us-gaap:AssetsCurrent |
| Total assets | at 2021-12-31 | $21.02bn | us-gaap:Assets |
| Current liabilities | at 2021-12-31 | $3.09bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2021-12-31 | $6.48bn | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2021-12-31 | $9.26bn | us-gaap:StockholdersEquity |

## Risk factors

As filed, 41,930 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.

### 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 $80 per Bbl and $6.00 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;
- 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 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;
- changes in trade relations and policies, including restrictions on oil, gas and NGL exports by the U.S., Russia or other producing countries, as well as the imposition of tariffs by the U.S. or China; and
- other governmental regulations and taxes.

**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 have created significant volatility, uncertainty and turmoil in the oil and gas industry. 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. This decline contributed to a swift and material deterioration in commodity prices in early 2020. Although commodity prices subsequently recovered, COVID-19 or its variants may lead to similar protracted periods of depressed commodity prices, which in turn could have significant adverse consequences for our financial condition and liquidity. Moreover, the COVID-19 pandemic has contributed to disruption and volatility in our supply chain, which has resulted, and may continue to result, in increased costs and delays for pipe and other materials needed for our operations.

The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused us and our service providers to modify certain of our business practices. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the virus, including the risk of infection of key employees. Our operations also may be adversely affected if we or our service providers are unable to retain sufficient personnel or such personnel are unable to work effectively, including because of illness, quarantines, government actions or other restrictions in connection with the pandemic. Moreover, our ability to perform certain functions could be disrupted or otherwise impaired by new business practices arising from the pandemic. For example, our reliance on technology has necessarily increased due to the encouragement of remote communications and other social-distancing practices, which could make us more vulnerable to cyber attacks.

The COVID-19 pandemic and its related effects continue to evolve. The ultimate extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on future developments, including, but not limited to, the nature, duration and spread of the virus, the vaccination and other responsive actions to stop its spread or address its effects and the duration, timing and severity of the related consequences on commodity prices and the economy more generally. Any extended period of depressed commodity prices or general economic disruption as a result of a pandemic would adversely affect our business, financial condition and results of operations.

### 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, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. Consequently, material revisions to existing reserves estimates may occur as a result of changes in any of these 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 wells, 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.

### 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, rules 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. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, including corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions.

In addition, 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. 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 and increase taxes, royalties and other amounts payable to governments or governmental agencies. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. 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 directing the Secretary of the Interior to pause on entering new oil and gas leases on public lands to the extent possible and to launch a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands. Although the pause on leasing was lifted in June 2021, the Department of the Interior subsequently issued its report on the federal leasing program in November 2021. The report recommended various changes to the program, including, among other things, increasing royalty and rental rates, enhancing bonding requirements and applying a more rigorous land-use planning process prior to leasing. However, certain of the report’s recommendations require Congressional actions, and we cannot predict to what extent, if any, the Department of the Interior may be able to promulgate rules implementing the 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, 2021, 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 finalized in 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a report in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources in certain circumstances. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands but subsequently issued a repeal of those regulations in 2017. Moreover, several states 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. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular.

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 northern and central Oklahoma, southeastern New Mexico, western Texas 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 recently imposed limits on certain salt-water disposal well activities in portions of the Midland Basin. 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. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.

*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 (such as intangible drilling costs) 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, new taxes are from time to time proposed (such as minimum taxes on net book income) and, if enacted, could adversely impact us.

### 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 proposed rules in November 2021 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. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year. Congress also recently considered legislation that included a proposal to apply a fee on certain methane emissions from oil and gas facilities, although the fate of this “methane fee” is uncertain at this time. 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. 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 highlighted 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 and directing federal agencies to procure electric vehicles. 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 November 2021, pursuant to which over 100 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 resulting from the changing perception of 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.

### 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.

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 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 sub-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 and gender 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. Although we cannot predict the ultimate impact of laws and related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements.

### 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 syndicated revolving 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, which could adversely impact our financial results and condition.

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

As of December 31, 2021, we had total indebtedness of $6.5 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 cash flows from operations 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, forecasted production growth and commodity prices. We are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. 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 any credit facility borrowing as well as the cost of any other future debt.

### Cyber Attacks 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 cyber attack related activities, which have increasingly targeted our industry. Cyber attackers 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. These attacks may be perpetrated by third parties or insiders. Techniques used in these attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be performed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions or breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

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

Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, 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 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, accidents, field labor issues or strikes. Additionally, the midstream operators may be subject to constraints that limit their ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.

### 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.

### 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 and personnel required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have financial and other resources substantially greater than ours and may have established superior strategic long-term positions and relationships, including with respect to midstream take-away capacity. 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.

### Our Business Could Be Adversely Impacted by Investors Attempting to Effect Change

Investors may from time to time attempt to effect changes to our business or governance, 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 under ESG metrics. Such actions could adversely impact our business by distracting our Board of Directors and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and 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, such as the Merger, 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 authorize 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, 986 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.

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 June 4, 2021, we received a 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 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, 64,983 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 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2020 Annual Report on Form 10-K.

### Executive Overview

The Merger has helped us become a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerates our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. We remain focused on building economic value by executing on our strategic priorities of achieving disciplined oil volume growth, capturing operational and corporate synergies, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items:

- 2021 production totaled 572 MBoe/d, exceeding our plan by 2%.
- Achieved approximately $600 million in merger-related annual cost savings during 2021.
- Redeemed approximately $1.2 billion of senior notes in 2021.
- Exited 2021 with $5.3 billion of liquidity, including $2.3 billion of cash, with no debt maturities until 2023.
- Generated $4.9 billion of operating cash flow in 2021.
- Including variable dividends, paid dividends of approximately $1.3 billion during 2021 and have declared $663 million of dividends to be paid in the first quarter of 2022.
- Increased our share repurchase program to $1.6 billion and repurchased approximately 14 million of our common shares in the fourth quarter of 2021 for approximately $589 million or $42.15 per share.
- Established environmental performance targets focused on reducing the carbon intensity of our operations.

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

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

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 $67.86 per Bbl and $3.85 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. Led by an 85% and 71% increase in Henry Hub and WTI from 2020 to 2021, respectively, our unhedged combined realized price rose 107%. Additionally, volumes increased 72% from 2020 to 2021 primarily due to the Merger as well as continued development of assets in the Delaware Basin.

Our net earnings in recent years have been significantly impacted by asset impairments and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in 2019, 2020 and 2021 included a $0.5 billion, $0.1 billion and $0.1 billion hedge valuation loss, respectively, net of taxes. Additionally, net earnings in 2020 included $2.2 billion of asset impairments on our proved and unproved properties, net of taxes, due to reduced demand from the COVID-19 pandemic. Excluding these amounts, our core earnings have been more stable over recent years but continue to be heavily influenced by commodity prices.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. Our cash flow and EBITDAX increased from 2020 to 2021 primarily due to the higher commodity prices and the increase in sold volumes driven by the Merger and improved post-merger operating performance.

We exited 2021 with $5.3 billion of liquidity, comprised of $2.3 billion of cash and $3.0 billion of available credit under our Senior Credit Facility. We currently have $6.5 billion of debt outstanding with no maturities until August 2023. We currently have approximately 20% and 30% of our 2022 oil and gas production hedged, respectively. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub and NYMEX last day natural gas indices. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.

As commodity prices and our operating performance strengthen and bolster our financial condition, we have authorized opportunistic repurchases of up to $1.6 billion shares of our common stock through the end of 2022. We repurchased approximately 14 million shares in the fourth quarter of 2021 for approximately $589 million or $42.15 per share. Additionally, we continue funding our fixed plus variable dividends, which totaled $1.3 billion in 2021. We recently declared a dividend payable in the first quarter of 2022 for $663 million.

### Business and Industry Outlook

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

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

Our disciplined strategy is in response to current market fundamentals that indicate a continued recovery in global oil demand along with an outlook for strong market prices for crude oil and natural gas that also remain inherently volatile. In 2021, WTI oil prices averaged $67.86 per barrel versus $39.59 per barrel in 2020. Crude prices experienced significant improvement from the prior year, but volatility remained due to OPEC oil supply uncertainty and market fears from new COVID-19 variants that could risk the global recovery from the pandemic. Looking ahead, current market fundamentals indicate that 2022 crude pricing is expected to continue to stabilize, supported both by a continued recovery in global demand with the easing of travel restrictions and expected continued capital discipline by oil producers. However, uncertainty still exists depending on new COVID-19 variants, as well as actions taken by OPEC+ countries in supporting a balanced global crude supply. Natural gas prices rebounded in 2021 due to continued global economic recovery, supply constraints and production declines. U.S. liquefied natural gas exports also strengthened in 2021 with increased spot prices in Asia and Europe due to increased demand as a result of lifting COVID-19 restrictions and unplanned outages at liquefied natural gas export facilities in other countries. Looking forward, natural gas and NGL prices are expected to flatten or decrease due to slowing growth in liquefied natural gas exports, rising U.S. natural gas production and warmer-than-expected weather.

Our strategy of spending well within cash flow mitigates risks to our financial strength due to commodity market volatility and provides for a lower level of hedging. Our 2022 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 20% of our anticipated oil volumes and 30% of our anticipated gas volumes. Further insulating our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges to protect price realizations across our portfolio.

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

### Results of Operations

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

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

### Production Volumes

| Oil (MBbls/d) | 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 197 | 68% | 85 | +133% |
| Anadarko Basin | 15 | 5% | 20 | - 27% |
| Williston Basin | 41 | 14% | — | N/M |
| Eagle Ford | 18 | 6% | 24 | - 25% |
| Powder River Basin | 15 | 5% | 19 | - 21% |
| Other | 4 | 2% | 7 | - 36% |
| Total | 290 | 100% | 155 | +88% |

| Gas (MMcf/d) | 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 535 | 60% | 248 | +116% |
| Anadarko Basin | 217 | 24% | 252 | - 14% |
| Williston Basin | 58 | 7% | — | N/M |
| Eagle Ford | 58 | 7% | 77 | - 24% |
| Powder River Basin | 20 | 2% | 23 | - 14% |
| Other | 2 | 0% | 3 | - 53% |
| Total | 890 | 100% | 603 | +48% |

| NGLs (MBbls/d) | 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 87 | 66% | 37 | +137% |
| Anadarko Basin | 24 | 18% | 27 | - 11% |
| Williston Basin | 9 | 7% | — | N/M |
| Eagle Ford | 9 | 6% | 10 | - 15% |
| Powder River Basin | 3 | 2% | 3 | - 2% |
| Other | 1 | 1% | 1 | +0% |
| Total | 133 | 100% | 78 | +70% |

| Combined (MBoe/d) | 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 374 | 65% | 163 | +130% |
| Anadarko Basin | 75 | 13% | 90 | - 16% |
| Williston Basin | 60 | 11% | — | N/M |
| Eagle Ford | 37 | 6% | 46 | - 21% |
| Powder River Basin | 21 | 4% | 26 | - 18% |
| Other | 5 | 1% | 8 | - 40% |
| Total | 572 | 100% | 333 | +72% |

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

### Realized Prices

| Oil (per Bbl) | 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| WTI index | $67.86 |  | $39.59 | +71% |
| Realized price, unhedged | $65.98 | 97% | $35.95 | +84% |
| Cash settlements | $(11.60) |  | $4.81 |  |
| Realized price, with hedges | $54.38 | 80% | $40.76 | +33% |

| Gas (per Mcf) | 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| Henry Hub index | $3.85 |  | $2.08 | +85% |
| Realized price, unhedged | $3.40 | 88% | $1.48 | +130% |
| Cash settlements | $(0.66) |  | $0.18 |  |
| Realized price, with hedges | $2.74 | 71% | $1.66 | +65% |

| NGLs (per Bbl) | 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| WTI index | $67.86 |  | $39.59 | +71% |
| Realized price, unhedged | $29.52 | 44% | $11.72 | +152% |
| Cash settlements | $(0.38) |  | $0.18 |  |
| Realized price, with hedges | $29.14 | 43% | $11.90 | +145% |

| Combined (per Boe) | 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| Realized price, unhedged | $45.68 | $22.10 | +107% |
| Cash settlements | $(7.01) | $2.60 |  |
| Realized price, with hedges | $38.67 | $24.70 | +57% |

From 2020 to 2021, realized prices contributed to a $4.7 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to all products in 2021.

### Hedge Settlements

|  | 2021 Q | 2020 | Change |
| --- | ---: | ---: | ---: |
| Oil | $(1,230) | $271 | - 554% |
| Natural gas | (213) | 40 | - 633% |
| NGL | (19) | 5 | - 480% |
| Total cash settlements (1) | $(1,462) | $316 | - 563% |

(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

|  | 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| LOE | $859 | $425 | +102% |
| Gathering, processing & transportation | 606 | 508 | +19% |
| Production taxes | 633 | 170 | +272% |
| Property taxes | 33 | 20 | +65% |
| Total | $2,131 | $1,123 | +90% |
| Per Boe: |  |  |  |
| LOE | $4.12 | $3.49 | +18% |
| Gathering, processing & transportation | $2.91 | $4.17 | - 30% |
| Percent of oil, gas and NGL sales: |  |  |  |
| Production taxes | 6.6% | 6.3% | +5% |

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

### Field-Level Cash Margin

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

| Field-level cash margin (Non-GAAP) | 2021 | $ per BOE | 2020 | $ per BOE |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | $5,183 | $37.98 | $946 | $15.86 |
| Anadarko Basin | 616 | $22.46 | 204 | $6.22 |
| Williston Basin | 759 | $34.79 | — | N/M |
| Eagle Ford | 474 | $35.33 | 229 | $13.46 |
| Powder River Basin | 290 | $37.83 | 159 | $16.93 |
| Other | 78 | $42.00 | 34 | $10.93 |
| Total | $7,400 | $35.47 | $1,572 | $12.89 |

### DD&A and Asset Impairments

|  | 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| Oil and gas per Boe | $9.83 | $9.90 | - 1% |
| Oil and gas | $2,050 | $1,207 | +70% |
| Other property and equipment | 108 | 93 | +16% |
| Total | $2,158 | $1,300 | +66% |
| Asset impairments | $— | $2,693 | N/M |

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

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

### General and Administrative Expense

|  | 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| G&A per Boe | $1.88 | $2.77 | - 32% |
| Labor and benefits | $255 | $206 | +24% |
| Non-labor | 136 | 132 | +3% |
| Total | $391 | $338 | +16% |

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

### Other Items

|  | 2021 | 2020 | Change in earnings |
| --- | ---: | ---: | ---: |
| Commodity hedge valuation changes (1) | $(82) | $(161) | $79 |
| Marketing and midstream operations | (19) | (35) | 16 |
| Exploration expenses | 14 | 167 | 153 |
| Asset dispositions | (168) | (1) | 167 |
| Net financing costs | 329 | 270 | (59) |
| Restructuring and transaction costs | 258 | 49 | (209) |
| Other, net | (43) | (34) | 9 |
|  |  |  | $156 |

(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.

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

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

Net financing costs increased as a result of the WPX debt assumed in the Merger, partially offset by a $30 million gain associated with our debt retirements in 2021. For additional information, see Note 2 and Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report.

Restructuring and transaction costs in 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. Restructuring and transaction costs in 2020 relate to workforce reductions, the associated employee severance benefits related to cost reduction plans and approximately $8 million of transaction costs related to the Merger. For additional information, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

### Income Taxes

|  | 2021 | 2020 |
| --- | ---: | ---: |
| Current expense (benefit) | $16 | $(219) |
| Deferred expense (benefit) | 49 | (328) |
| Total expense (benefit) | $65 | $(547) |
| Effective income tax rate | 2% | 18% |

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

### 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, 2021 | 2020 |
| --- | ---: | ---: |
| Operating cash flow from continuing operations | $4,899 | $1,464 |
| WPX acquired cash | 344 | — |
| Divestitures of property and equipment | 79 | 34 |
| Capital expenditures | (1,989) | (1,153) |
| Debt activity, net | (1,302) | — |
| Repurchases of common stock | (589) | (38) |
| Common stock dividends | (1,315) | (257) |
| Noncontrolling interest activity, net | (41) | 7 |
| Other | (52) | (26) |
| Net change in cash, cash equivalents and restricted cash from discontinued operations | — | 362 |
| Net change in cash, cash equivalents and restricted cash | $34 | $393 |
| Cash, cash equivalents and restricted cash at end of period | $2,271 | $2,237 |

#### Operating Cash Flow and WPX Acquired Cash

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow increased 235% during 2021 compared to 2020. The increase was due to the Merger and commodity prices significantly increasing in 2021, as well as cost synergies captured after the Merger.

#### Divestitures of Property and Equipment

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

#### Capital Expenditures

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

|  | Year Ended December 31, 2021 | 2020 |
| --- | ---: | ---: |
| Delaware Basin | $1,535 | $734 |
| Anadarko Basin | 53 | 23 |
| Williston Basin | 77 | — |
| Eagle Ford | 122 | 172 |
| Powder River Basin | 73 | 172 |
| Other | 3 | 8 |
| Total oil and gas | 1,863 | 1,109 |
| Midstream | 64 | 31 |
| Other | 62 | 13 |
| Total capital expenditures | $1,989 | $1,153 |

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. Capital expenditures increased in 2021 primarily due to the Merger closing on January 7, 2021 and results now include activity related to WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Our capital program is designed to operate within operating cash flow. This is evidenced by our operating cash flow fully funding capital expenditures for 2021 and 2020. Our capital investment program is driven by a disciplined allocation process focused on maximizing returns.

#### Debt Activity, Net

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

#### Repurchases of Common Stock and Shareholder Distributions

We repurchased 14 million shares of common stock for $589 million in 2021 and 2.2 million shares of common stock for $38 million in 2020 under share repurchase programs authorized by our Board of Directors. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report.

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

| 2021: | Fixed | Variable/Special | Total | Rate Per Share |
| --- | ---: | ---: | ---: | ---: |
| 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 |  |
| 2020: |  |  |  |  |
| First quarter | $34 | $— | $34 | $0.09 |
| Second quarter | 42 | — | 42 | $0.11 |
| Third quarter | 43 | — | 43 | $0.11 |
| Fourth quarter | 41 | 97 | 138 | $0.37 |
| Total year-to-date | $160 | $97 | $257 |  |

#### Noncontrolling Interest Activity, net

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

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

### Liquidity

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

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

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

#### Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of 2021, we held approximately $2.3 billion of cash, inclusive of $160 million of cash restricted primarily for retained obligations related to divested assets. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as these variables may differ from our expectations.

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

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2021 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

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

*Operating Expenses –* Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices. Furthermore, the COVID-19 pandemic has contributed to disruption and volatility in our supply chain, which has resulted, and may continue to result, in increased costs and delays for pipe and other materials needed for our operations.

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

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

#### Repayment of Debt

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

#### Credit Availability

We have $3.0 billion of available borrowing capacity under our Senior Credit Facility at December 31, 2021. The Senior Credit Facility matures on October 5, 2024, with the option to extend the maturity date by two additional one-year periods subject to lender consent. Subsequent to October 5, 2023, the borrowing capacity decreases to $2.8 billion. The Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2021, there were no borrowings under our commercial paper program. See Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of December 31, 2021, we were in compliance with this covenant with a 25% debt-to-capitalization ratio.

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

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

#### Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB- with a positive outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa3 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

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

#### Fixed Plus Variable Dividend

Following the closing of the Merger, we initiated a new “fixed plus variable” dividend strategy. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In February 2022, our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Board. Devon paid $1.3 billion of total fixed and variable dividends during 2021.

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

#### Share Repurchase Program

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

#### Capital Expenditures

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

#### Contractual Obligations

As of December 31, 2021, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, retained obligations related to our Barnett Shale assets and Canadian business, operational agreements, drilling and facility obligations and various tax obligations. As discussed above, we estimate the combination of our sources of capital will continue to be adequate to fund our short- and long-term contractual obligations, including the obligations we assumed through the Merger. See Notes 6, 8, 14, 15, 16 and 20 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

### Contingencies and Legal Matters

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

### Critical Accounting Estimates

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

### Purchase Accounting

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

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

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

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

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

#### Successful Efforts Method of Accounting and Classification

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

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2021, all suspended well costs have been suspended for less than one year.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2021, Devon had approximately $733 million of undeveloped leasehold costs. Of the remaining undeveloped leasehold costs at December 31, 2021, approximately $19 million is scheduled to expire in 2022. The leasehold expiring in 2022 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

#### Reserves

Our estimates of proved and proved developed reserves are a major component of DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by a third-party petroleum consulting firm. In 2021, 88% of our reserves were subjected to such an audit.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

#### Valuation of Long-Lived Assets

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

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

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

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

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

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

### Income Taxes

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

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during 2021 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next two years. See Note 8 in “Item 8. Financial Statements and Supplementary Data” in this report for further discussion regarding our net operating losses and tax credits available to be carried forward and used in future years.

### Goodwill

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of goodwill is less than its carrying amount. As part of our qualitative assessment, we considered the general macro-economic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value is compared to the carrying value. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analysis including comparable companies and transactions and premiums paid. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions.

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

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

### Non-GAAP Measures

### Core Earnings

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2021 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings (loss) excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our quarterly financial results. For more information on the results of discontinued operations for our Barnett Shale assets and Canadian operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2021 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance, changes in tax legislation, fair value changes in derivative financial instruments, costs associated with the early retirement of debt and restructuring and transaction costs associated with the workforce reductions in 2021.

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

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

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

| 2021 Total | Year Ended December 31, Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share |
| --- | ---: | ---: | ---: | ---: |
| 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 |
| **2020** |  |  |  |  |
| **Continuing Operations** |  |  |  |  |
| 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) |

40

| 2019 Continuing Operations | Year ended December 31, Before tax | After tax | After Noncontrolling Interests | Per Diluted Share |
| --- | ---: | ---: | ---: | ---: |
| Loss attributable to Devon (GAAP) | $(109) | $(79) | $(81) | $(0.21) |
| Adjustments: |  |  |  |  |
| Asset dispositions | (48) | (37) | (37) | (0.09) |
| Asset and exploration impairments | 20 | 15 | 15 | 0.04 |
| Fair value changes in financial instruments | 623 | 480 | 480 | 1.19 |
| Restructuring and transaction costs | 84 | 64 | 64 | 0.15 |
| Core earnings attributable to Devon (Non-GAAP) | $570 | $443 | $441 | $1.08 |
| **Discontinued Operations** |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(632) | $(274) | $(274) | $(0.68) |
| Adjustments: |  |  |  |  |
| Gain on sale of Canadian operations | (223) | (425) | (425) | (1.05) |
| Asset and exploration impairments | 785 | 613 | 613 | 1.52 |
| Deferred tax asset valuation allowance | — | 24 | 24 | 0.06 |
| Early retirement of debt | 58 | 45 | 45 | 0.11 |
| Fair value changes in financial instruments and foreign currency and other | (33) | (37) | (37) | (0.10) |
| Restructuring and transaction costs | 248 | 183 | 183 | 0.45 |
| Core earnings attributable to Devon (Non-GAAP) | $203 | $129 | $129 | $0.31 |
| **Total** |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(741) | $(353) | $(355) | $(0.89) |
| Adjustments: |  |  |  |  |
| Continuing Operations | 679 | 522 | 522 | 1.29 |
| Discontinued Operations | 835 | 403 | 403 | 0.99 |
| Core earnings attributable to Devon (Non-GAAP) | $773 | $572 | $570 | $1.39 |

### 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, 2021 | 2020 | 2019 |
| --- | ---: | ---: | ---: |
| **Net earnings (loss) (GAAP)** | $2,833 | $(2,671) | $(353) |
| Net loss from discontinued operations, net of tax | — | 128 | 274 |
| Financing costs, net | 329 | 270 | 250 |
| Income tax expense (benefit) | 65 | (547) | (30) |
| Exploration expenses | 14 | 167 | 58 |
| Depreciation, depletion and amortization | 2,158 | 1,300 | 1,497 |
| Asset impairments | — | 2,693 | — |
| Asset dispositions | (168) | (1) | (48) |
| Share-based compensation | 77 | 76 | 83 |
| Derivative and financial instrument non-cash valuation changes | 82 | 161 | 623 |
| Restructuring and transaction costs | 258 | 49 | 84 |
| Accretion on discounted liabilities and other | (43) | (34) | 5 |
| **EBITDAX (Non-GAAP)** | 5,605 | 1,591 | 2,443 |
| Marketing and midstream revenues and expenses, net | 19 | 35 | (53) |
| Commodity derivative cash settlements | 1,462 | (316) | (170) |
| General and administrative expenses, cash-based | 314 | 262 | 392 |
| **Field-level cash margin (Non-GAAP)** | $7,400 | $1,572 | $2,612 |

42

## 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, 2021 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, 2021, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $195 million.

### Interest Rate Risk

At December 31, 2021, we had total debt of $6.5 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, 2021.

## 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, 2021 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 16, 2022, management concluded that its internal control over financial reporting was effective as of December 31, 2021.

The effectiveness of our internal control over financial reporting as of December 31, 2021 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, 2021, 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 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Filed Feb 16, 2022.
Source: SEC EDGAR, the filing index for accession 0001564590-22-005321. Last ingested by Listed: Nov 6, 2026, 13:26 ET. No prices; not investment advice.