# DEVON ENERGY CORP/DE (DVN) FY 2024 MD&A

Verbatim Item 7 Management's Discussion and Analysis from DEVON ENERGY CORP/DE's 10-K for fiscal year 2024.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1090012/000095017025022844/dvn-20241231.htm
Accession: 0000950170-25-022844
Filing date: 2025-02-19
Report date: 2024-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/DVN/
All MD&A years: /company/DVN/mda/
Previous year: /company/DVN/mda/fy2023/ (FY 2023)
Next year: /company/DVN/mda/fy2025/ (FY 2025)

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

Introduction

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

The following discussion and analyses primarily focus on 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 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 2023 Annual Report on Form 10-K.

Executive Overview

We are a leading independent oil and natural gas exploration and production company whose operations are focused onshore in the United States. Our operations are currently focused in four core areas: the Delaware Basin, Rockies, Eagle Ford and Anadarko. Our asset base is underpinned by premium acreage in the economic core of the Delaware Basin and our diverse, top-tier resource plays provide a deep inventory of opportunities for years to come.

On September 27, 2024, we acquired the Williston Basin business of Grayson Mill for total consideration of approximately $5.0 billion, consisting of $3.5 billion of cash and approximately 37.3 million shares of Devon common stock, including purchase price adjustments. The acquisition will allow us to efficiently expand our oil production and operating scale, creating immediate and long-term, sustainable value to shareholders over time.

As evidenced by this acquisition, we remain focused on building economic value by executing on our strategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing operational excellence. Our recent performance highlights for these priorities include the following items for 2024:

•
Oil production totaled 347 MBbls/d, an 8% increase year over year.

•
Through 2024, completed approximately 67% of our authorized $5.0 billion share repurchase program, with approximately 69 million of our common shares repurchased for approximately $3.3 billion, or $48.46 per share, since inception of the plan.

•
Retired $472 million of senior notes.

•
Exited with $3.8 billion of liquidity, including $0.8 billion of cash.

•
Generated $6.6 billion of operating cash flow.

•
Including variable dividends, paid dividends of $937 million.

•
Earnings attributable to Devon were $2.9 billion, or $4.56 per diluted share.

•
Core earnings (Non-GAAP) were $3.1 billion, or $4.82 per diluted share.

We remain committed to capital discipline and delivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from inflation and geopolitical events. Our cash-return objectives remain focused on opportunistic share repurchases, funding our dividends, repaying debt at upcoming maturities and building cash balances.

Our net earnings and operating cash flow are highly dependent upon oil, gas and NGL prices which can be incredibly volatile due to several varying factors. Commodity prices were strong during 2022 as the continued recovery from the COVID-19 pandemic increased demand for oil and gas commodities, while economic sanctions imposed on Russia and restraint from OPEC+ on production growth both simultaneously impacted the supply of these commodities. In 2023, commodity prices weakened primarily due to economic uncertainty surrounding inflation and increased interest rates as well as certain geopolitical events. During 2024, oil and NGL prices remained stable from the prior year while gas prices decreased primarily due to warmer weather impacts and excess

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supply. The graphs below show the trends in commodity prices over the past three years and their related impact on our net earnings, operating cash flow and capital investments.

As we dependably generate strong cash flow results as shown above, we will continue to prioritize delivering cash returns to shareholders through share repurchases and dividends while maintaining a strong liquidity position. Since the inception of our authorized $5.0 billion share repurchase program, we have repurchased approximately 69 million common shares for approximately $3.3 billion, or $48.46 per share. We also returned value to shareholders by paying dividends of $937 million during 2024. We exited 2024 with $3.8 billion of liquidity, comprised of $0.8 billion of cash and $3.0 billion of available credit under our 2023 Senior Credit Facility. We currently have $8.9 billion of debt outstanding, of which approximately $485 million is classified as short-term. Additionally, to help mitigate the volatility of commodity prices and protect ourselves from downside risk, we currently have approximately 30% of our anticipated 2025 oil and gas production hedged.

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Business and Industry Outlook

In 2024, Devon marked its 53rd anniversary in the oil and gas business and its 36th year as a public company. We generated $6.6 billion of operating cash flow in 2024 as a result of the strength of our portfolio of assets and our operational execution. Our portfolio benefited from the acquisition of Grayson Mill that allowed us to efficiently expand our oil production and operating scale while capturing a meaningful runway of highly economic drilling inventory. The transaction created immediate value within our financial framework by delivering sustainable accretion to earnings and free cash flow. Operating cash flow in 2024 remained consistent with 2023, despite a decline in commodity prices, due to operational outperformance, capital efficiency gains and the positive contributions from our Grayson Mill acquisition.

We remain committed to continuing our track record of industry leading return of capital to our shareholders, underpinned by low capital reinvestment rates and a disciplined, returns-driven strategy which is designed to be successful through economic cycles. In 2024, we returned approximately $2.0 billion of cash to shareholders through cash dividends and share repurchases, and will continue to prioritize this shareholder return strategy in 2025.

In 2024, WTI oil prices averaged $75.79 per Bbl versus $77.62 per Bbl in 2023, reflecting a downward trend as oil prices remained volatile even with continued capital discipline by global oil producers. Oil is expected to remain volatile in 2025 due to geopolitical risks to supply, forecasted stronger non-OPEC supply, and improving global demand growth expectations. Henry Hub natural gas prices fell in 2024, averaging $2.27 per Mcf compared to $2.74 per Mcf in 2023. For 2025, natural gas prices are expected to increase compared with 2024 prices due to increased demand, driven by rising LNG exports, strong powerburn as well as discipline from natural gas producers. Our 2025 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 30% of our anticipated oil and gas volumes. In order to further insulate our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges to protect price realizations across our portfolio.

Our commitment to capital discipline and capital efficiency remains unchanged with our 2025 capital program. Similar to 2024, the majority of our 2025 capital, or approximately 55%, is expected to be focused on our highest returning oil play, the Delaware Basin. Our Williston Basin assets will receive additional capital allocation through 2025 as we work to develop the newly acquired Grayson Mill assets. The remainder of our 2025 capital will continue to be deployed to our other core areas of Eagle Ford, Anadarko Basin and Powder River Basin. Our 2025 capital is expected to be approximately 7% higher than 2024 primarily due to increased activity in the Williston Basin. Due to our strategy of spending within cash flow, we expect to continue generating material amounts of free cash flow for 2025.

Results of Operations

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

Our 2024 net earnings were $2.9 billion, compared to net earnings of $3.8 billion for 2023. The graph below shows the change in net earnings from 2023 to 2024. The material changes are further discussed by category on the following pages.

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Production Volumes

[[GREPCENT_TABLE]]
[["","","2024","","","% of Total","","","2023","","","Change"],["Oil (MBbls/d)"],["Delaware Basin","","","220","","","","63","%","","","211","","","","4","%"],["Rockies","","","65","","","","19","%","","","50","","","","30","%"],["Eagle Ford","","","46","","","","13","%","","","42","","","","10","%"],["Anadarko Basin","","","13","","","","4","%","","","14","","","","-7","%"],["Other","","","3","","","","1","%","","","3","","","N/M"],["Total","","","347","","","","100","%","","","320","","","","8","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","2024","","","% of Total","","","2023","","","Change"],["Gas (MMcf/d)"],["Delaware Basin","","","732","","","","61","%","","","657","","","","11","%"],["Rockies","","","124","","","","10","%","","","76","","","","63","%"],["Eagle Ford","","","98","","","","9","%","","","82","","","","20","%"],["Anadarko Basin","","","241","","","","20","%","","","238","","","","1","%"],["Other","","","1","","","","0","%","","","1","","","N/M"],["Total","","","1,196","","","","100","%","","","1,054","","","","13","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","2024","","","% of Total","","","2023","","","Change"],["NGLs (MBbls/d)"],["Delaware Basin","","","123","","","","64","%","","","107","","","","16","%"],["Rockies","","","21","","","","11","%","","","11","","","","91","%"],["Eagle Ford","","","17","","","","9","%","","","15","","","","13","%"],["Anadarko Basin","","","29","","","","15","%","","","28","","","","4","%"],["Other","","","1","","","","1","%","","","1","","","N/M"],["Total","","","191","","","","100","%","","","162","","","","18","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","2024","","","% of Total","","","2023","","","Change"],["Combined (MBoe/d)"],["Delaware Basin","","","465","","","","63","%","","","427","","","","9","%"],["Rockies","","","107","","","","15","%","","","73","","","","47","%"],["Eagle Ford","","","79","","","","11","%","","","71","","","","11","%"],["Anadarko Basin","","","82","","","","11","%","","","82","","","","0","%"],["Other","","","4","","","","0","%","","","5","","","","-6","%"],["Total","","","737","","","","100","%","","","658","","","","12","%"]]
[[/GREPCENT_TABLE]]

From 2023 to 2024, the change in volumes contributed to a $1.1 billion increase in earnings. The increase in volumes was primarily due to increased activity in the Delaware Basin and Eagle Ford as well as the Grayson Mill acquisition in the Rockies, which closed in the third quarter of 2024.

Due to the Grayson Mill acquisition and increased activity across our portfolio, we expect volumes to increase in 2025 and range from approximately 805 to 825 MBoe/d.

Realized Prices

[[GREPCENT_TABLE]]
[["","","2024","","","Realization","","2023","","","Change"],["Oil (per Bbl)"],["WTI index","","$","75.79","","","","","$","77.62","","","","-2","%"],["Realized price, unhedged","","$","73.78","","","97%","","$","75.98","","","","-3","%"],["Cash settlements","","$","0.35","","","","","$","(0.28",")"],["Realized price, with hedges","","$","74.13","","","98%","","$","75.70","","","","-2","%"]]
[[/GREPCENT_TABLE]]

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[[GREPCENT_TABLE]]
[["","","2024","","","Realization","","2023","","","Change"],["Gas (per Mcf)"],["Henry Hub index","","$","2.27","","","","","$","2.74","","","","-17","%"],["Realized price, unhedged","","$","0.91","","","40%","","$","1.83","","","","-50","%"],["Cash settlements","","$","0.35","","","","","$","0.20"],["Realized price, with hedges","","$","1.26","","","56%","","$","2.03","","","","-38","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","2024","","","Realization","","2023","","","Change"],["NGLs (per Bbl)"],["WTI index","","$","75.79","","","","","$","77.62","","","","-2","%"],["Realized price, unhedged","","$","20.20","","","27%","","$","20.48","","","","-1","%"],["Cash settlements","","$","0.02","","","","","$","\u2014"],["Realized price, with hedges","","$","20.22","","","27%","","$","20.48","","","","-1","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change"],["Combined (per Boe)"],["Realized price, unhedged","","$","41.44","","","$","44.96","","","","-8","%"],["Cash settlements","","$","0.73","","","$","0.19"],["Realized price, with hedges","","$","42.17","","","$","45.15","","","","-7","%"]]
[[/GREPCENT_TABLE]]

From 2023 to 2024, realized prices contributed to an approximately $700 million decrease in earnings. This decrease was due to lower unhedged realized oil, gas and NGL prices which decreased primarily due to lower WTI and Henry Hub index prices. Additionally, gas prices were impacted by expanded regional gas price differentials in the Delaware Basin driven by infrastructure constraints. Realized prices were strengthened by hedge cash settlements across all commodities.

Hedge Settlements

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change"],["Oil","","$","44","","","$","(33",")","","","233","%"],["Natural gas","","","152","","","","80","","","","90","%"],["NGL","","","1","","","","\u2014","","","N/M"],["Total cash settlements (1)","","$","197","","","$","47","","","","319","%"]]
[[/GREPCENT_TABLE]]

(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

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change"],["LOE","","$","1,574","","","$","1,428","","","","10","%"],["Gathering, processing & transportation","","","790","","","","702","","","","13","%"],["Production taxes","","","748","","","","713","","","","5","%"],["Property taxes","","","71","","","","85","","","","-16","%"],["Total","","$","3,183","","","$","2,928","","","","9","%"],["Per Boe:"],["LOE","","$","5.83","","","$","5.95","","","","-2","%"],["Gathering, processing & transportation","","$","2.93","","","$","2.92","","","","0","%"],["Percent of oil, gas and NGL sales:"],["Production taxes","","","6.7","%","","","6.6","%","","","1","%"]]
[[/GREPCENT_TABLE]]

LOE and gathering, processing and transportation and production taxes increased primarily due to increased activity and the Grayson Mill acquisition in the Rockies.

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Field-Level Cash Margin

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

[[GREPCENT_TABLE]]
[["","","2024","","","$ per BOE","","","2023","","","$ per BOE"],["Field-level cash margin (Non-GAAP)"],["Delaware Basin","","$","5,197","","","$","30.56","","","$","5,359","","","$","34.38"],["Rockies","","","1,122","","","$","28.61","","","","863","","","$","32.19"],["Eagle Ford","","","1,150","","","$","39.72","","","","1,074","","","$","41.71"],["Anadarko Basin","","","464","","","$","15.50","","","","508","","","$","16.94"],["Other","","","60","","","N/M","","","","59","","","N/M"],["Total","","$","7,993","","","$","29.63","","","$","7,863","","","$","32.76"]]
[[/GREPCENT_TABLE]]

DD&A

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change"],["Oil and gas per Boe","","$","11.70","","","$","10.27","","","","14","%"],["Oil and gas","","$","3,156","","","$","2,464","","","","28","%"],["Other property and equipment","","","99","","","","90","","","","11","%"],["Total","","$","3,255","","","$","2,554","","","","27","%"]]
[[/GREPCENT_TABLE]]

DD&A increased in 2024 primarily due to higher volumes as well as an increase in the oil and gas DD&A rate. The primary contributor to the higher DD&A rate was our 2023 drilling and development activity.

General and Administrative Expense

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change"],["G&A per Boe","","$","1.85","","","$","1.70","","","","9","%"],["Labor and benefits","","$","285","","","$","210","","","","36","%"],["Non-labor","","","215","","","","198","","","","9","%"],["Total","","$","500","","","$","408","","","","23","%"]]
[[/GREPCENT_TABLE]]

G&A increased in 2024 primarily due to higher employee compensation, driven in part by inflationary adjustments and the Grayson Mill acquisition. We also had an increase in non-labor costs which were primarily related to technology system upgrade projects.

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Other Items

[[GREPCENT_TABLE]]
[["","","2024","","","2023","","","Change in earnings"],["Commodity hedge valuation changes (1)","","$","(176",")","","$","71","","","$","(247",")"],["Marketing and midstream operations","","","(49",")","","","(60",")","","","11"],["Exploration expenses","","","28","","","","20","","","","(8",")"],["Asset dispositions","","","11","","","","(30",")","","","(41",")"],["Net financing costs","","","363","","","","308","","","","(55",")"],["Other, net","","","96","","","","38","","","","(58",")"],["","","","","","","","","$","(398",")"]]
[[/GREPCENT_TABLE]]

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

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

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

During the third quarter of 2024, we issued $3.25 billion of debt to partially fund the Grayson Mill acquisition. Additionally, we retired $472 million of debt in the third quarter of 2024. The net impact of this debt activity is expected to increase our annual net financing costs by approximately $180 million. For additional information, see Note 13 in "Part I. Financial Information - Item 1. Financial Statements" in this report.

For discussion on other, net, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

Income Taxes

[[GREPCENT_TABLE]]
[["","","2024","","","2023"],["Current expense","","$","459","","","$","465"],["Deferred expense","","","311","","","","376"],["Total expense","","$","770","","","$","841"],["Current tax rate","","","12","%","","","10","%"],["Deferred tax rate","","","9","%","","","8","%"],["Effective income tax rate","","","21","%","","","18","%"]]
[[/GREPCENT_TABLE]]

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

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Capital Resources, Uses and Liquidity

Sources and Uses of Cash

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2024","","","2023"],["Operating cash flow","","$","6,600","","","$","6,544"],["Grayson Mill acquired cash","","","147","","","","\u2014"],["Capital expenditures","","","(3,645",")","","","(3,883",")"],["Acquisitions of property and equipment","","","(3,808",")","","","(64",")"],["Divestitures of property and equipment","","","24","","","","26"],["Investment activity, net","","","(50",")","","","(21",")"],["Debt activity, net","","","2,747","","","","(242",")"],["Repurchases of common stock","","","(1,057",")","","","(979",")"],["Common stock dividends","","","(937",")","","","(1,858",")"],["Noncontrolling interest activity, net","","","1","","","","(8",")"],["Other","","","(51",")","","","(94",")"],["Net change in cash, cash equivalents and restricted cash","","$","(29",")","","$","(579",")"],["Cash, cash equivalents and restricted cash at end of period","","$","846","","","$","875"]]
[[/GREPCENT_TABLE]]

Operating Cash Flow

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow funded our capital expenditures, and we continued to return value to our shareholders by utilizing cash flow and cash balances for dividends and share repurchases.

Capital Expenditures

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2024","","","2023"],["Delaware Basin","","$","2,049","","","$","2,257"],["Rockies","","","504","","","","489"],["Eagle Ford","","","670","","","","775"],["Anadarko Basin","","","225","","","","196"],["Other","","","7","","","","6"],["Total oil and gas","","","3,455","","","","3,723"],["Midstream","","","101","","","","81"],["Other","","","89","","","","79"],["Total capital expenditures","","$","3,645","","","$","3,883"]]
[[/GREPCENT_TABLE]]

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our capital expenditures for 2024 represent approximately 55% of our operating cash flow.

Acquisitions of Property and Equipment

During the third quarter of 2024, we acquired the Williston Basin business of Grayson Mill. The transaction consisted of $3.5 billion of cash and approximately 37.3 million shares of Devon common stock. For additional information, please see Note 2 in “Part II. Item 8. Financial Statements and Supplementary Data” in this report.

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Divestitures of Property and Equipment

During 2024 and 2023, we received contingent earnout payments related to assets previously sold. For additional information, please see Note 2 in “Part II. Item 8. Financial Statements and Supplementary Data” in this report.

Investment Activity

During 2024 and 2023, Devon received distributions from our investments of $68 million and $32 million, respectively. Devon contributed $118 million and $53 million to our investments during 2024 and 2023, respectively.

Debt Activity

In 2024, Devon issued $1.25 billion of 5.20% senior notes due 2034 and $1.0 billion of 5.75% senior notes due 2054. Additionally, in 2024, Devon borrowed $1.0 billion from the Term Loan. These debt issuances helped fund the Grayson Mill acquisition. During 2024, we repaid $472 million of senior notes at maturity.

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

Shareholder Distributions and Stock Activity

We repurchased 24.2 million shares of common stock for $1.1 billion in 2024 and 19.1 million shares of common stock for $979 million in 2023 under the share repurchase program authorized by our Board of Directors. For additional information, see Note 17 in “Item 8. Financial Statements and Supplementary Data” in this report.

The following table summarizes our common stock dividends in 2024 and 2023. Devon most recently raised its fixed dividend by 10% from $0.20 to $0.22 per share in the first quarter of 2024. In addition to the fixed quarterly dividend, we paid a variable dividend in the first, second and third quarters of 2024 and each quarter of 2023. For additional information, see Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report.

[[GREPCENT_TABLE]]
[["","Fixed","","","Variable","","","Total","","","Rate Per Share"],["2024:"],["First quarter","$","143","","","$","156","","","$","299","","","$","0.44"],["Second quarter","","138","","","","85","","","","223","","","$","0.35"],["Third quarter","","136","","","","136","","","","272","","","$","0.44"],["Fourth quarter","","143","","","","\u2014","","","","143","","","$","0.22"],["Total year-to-date","$","560","","","$","377","","","$","937"],["2023:"],["First quarter","$","133","","","$","463","","","$","596","","","$","0.89"],["Second quarter","","128","","","","334","","","","462","","","$","0.72"],["Third quarter","","127","","","","185","","","","312","","","$","0.49"],["Fourth quarter","","127","","","","361","","","","488","","","$","0.77"],["Total year-to-date","$","515","","","$","1,343","","","$","1,858"]]
[[/GREPCENT_TABLE]]

Noncontrolling Interest Activity

During 2024 and 2023, we received $52 million and $37 million, respectively, of contributions from our noncontrolling interests in CDM. During 2024 and 2023, we distributed $51 million and $45 million, respectively, to our noncontrolling interests in CDM.

Liquidity

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

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On September 27, 2024, Devon acquired the Williston Basin business of Grayson Mill. This acquisition adds a high-margin production mix that enhances our position and efficiently expands our operating scale and production. The acquisition delivers sustainable accretion to earnings and free cash flow further supporting our cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders.

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

Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of 2024, we held approximately $850 million of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.

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

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2024 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2025.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices. We expect to mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.

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

Credit Availability

We had approximately $3.0 billion of available borrowing capacity under our 2023 Senior Credit Facility at December 31, 2024. In the first quarter of 2024, Devon exercised its option to extend the 2023 Senior Credit Facility maturity date from March 24, 2028 to March 24, 2029. Devon has the option to extend the March 24, 2029 maturity date by two additional one-year periods subject to lender consent. The 2023 Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2024, there were no borrowings under our commercial paper program. See Note 13 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The 2023 Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of December 31, 2024, we were in compliance with this covenant with a 26.5% debt-to-capitalization ratio.

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Our access to funds from the 2023 Senior Credit Facility is not subject to a specific funding condition requiring the absence of a “material adverse effect”. It is not uncommon for credit agreements to include such provisions. In general, these provisions can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement. While our credit agreement includes provisions qualified by material adverse effect as well as a covenant that requires us to report a condition or event having a material adverse effect, the obligation of the banks to fund the 2023 Senior Credit Facility is not conditioned on the absence of a material adverse effect.

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

Debt Ratings

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

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

Cash Returns to Shareholders

We are committed to returning cash to shareholders through dividends and share repurchases. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In addition to the fixed quarterly dividend, we may pay a variable dividend or complete share repurchases. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.

In February 2025, we raised our fixed dividend by 9%, to $0.24 per share, beginning in the first quarter of 2025. The dividend is payable in the first quarter of 2025 and is expected to total approximately $156 million.

Our Board of Directors has authorized a $5.0 billion share repurchase program that expires on June 30, 2026. Through February 14, 2025, we had executed $3.4 billion of the authorized program.

Capital Expenditures

Our 2025 capital expenditure budget is expected to be approximately $3.8 billion to $4.0 billion, which is approximately 7% higher than our 2024 capital expenditures primarily due to the Grayson Mill acquisition.

Contractual Obligations

As of December 31, 2024, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, operational agreements, drilling and facility obligations, various tax obligations and retained obligations related to our divested Canadian business. As discussed above, we estimate the combination of our sources of capital will continue to be adequate to fund our short- and long-term contractual obligations. See Notes 6, 13, 14, 15 and 18 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

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Tax Contingencies

As we are regularly audited by tax authorities, we have and will continue to have our tax positions challenged. Certain tax authorities require material cash deposits be made to further dispute and respond to any of our challenged tax positions.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates

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

Purchase Accounting

Periodically, we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the acquisition of the Williston Basin business of Grayson Mill. In connection with the acquisition, we allocated the $5.0 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the date of the acquisition. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the acquisition.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the acquisition. 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, drilling plans, 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 our 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.

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,

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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, 2024, all material suspended well costs have been suspended for less than one year.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2024, Devon had approximately $1.9 billion of undeveloped leasehold costs. Of the remaining undeveloped leasehold costs at December 31, 2024, none is scheduled to expire in 2025.

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 2024, 89% of our proved reserves were subjected to such an audit.

The passage of time provides additional information which may result in revisions to previous estimates to reflect updated information. In the past five years, annual revisions other than price to our proved reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 3% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. For example, revisions may be driven broadly by economic factors such as significant changes in operating costs, or they may be more focused such as in a given area or reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Valuation of Long-Lived Assets

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

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

Besides the risk-adjusted estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we utilize NYMEX forward strip prices and

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incorporate internally generated price forecasts along with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues.

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

None of our oil and gas assets were at risk of impairment as of December 31, 2024.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during 2024 for Devon.

Non-GAAP Measures

Core Earnings

We make reference to “core earnings attributable to Devon” and “core earnings per share attributable to Devon” in “Overview of 2024 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our quarterly financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2024 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), fair value changes in derivative financial instruments and restructuring and transaction costs.

Amounts excluded for 2023 and 2022 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance and fair value changes in derivative financial instruments.

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

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","Before Tax","","","After Tax","","","After NCI","","","Per Diluted Share"],["2024:"],["Earnings attributable to Devon (GAAP)","$","3,712","","","$","2,942","","","$","2,891","","","$","4.56"],["Adjustments:"],["Asset dispositions","","11","","","","9","","","","9","","","","0.01"],["Asset and exploration impairments","","5","","","","4","","","","4","","","","0.01"],["Fair value changes in financial instruments","","182","","","","143","","","","143","","","","0.23"],["Restructuring and transaction costs","","9","","","","7","","","","7","","","","0.01"],["Core earnings attributable to Devon (Non-GAAP)","$","3,919","","","$","3,105","","","$","3,054","","","$","4.82"],["2023:"],["Earnings attributable to Devon (GAAP)","$","4,623","","","$","3,782","","","$","3,747","","","$","5.84"],["Adjustments:"],["Asset dispositions","","(30",")","","","(24",")","","","(24",")","","","(0.04",")"],["Asset and exploration impairments","","5","","","","3","","","","3","","","","\u2014"],["Deferred tax asset valuation allowance","","\u2014","","","","(1",")","","","(1",")","","","\u2014"],["Fair value changes in financial instruments","","(74",")","","","(58",")","","","(58",")","","","(0.09",")"],["Core earnings attributable to Devon (Non-GAAP)","$","4,524","","","$","3,702","","","$","3,667","","","$","5.71"],["2022:"],["Earnings attributable to Devon (GAAP)","$","7,775","","","$","6,037","","","$","6,015","","","$","9.12"],["Adjustments:"],["Asset dispositions","","(44",")","","","(34",")","","","(34",")","","","(0.05",")"],["Asset and exploration impairments","","13","","","","10","","","","10","","","","0.02"],["Deferred tax asset valuation allowance","","\u2014","","","","17","","","","17","","","","0.03"],["Fair value changes in financial instruments","","(690",")","","","(532",")","","","(532",")","","","(0.81",")"],["Core earnings attributable to Devon (Non-GAAP)","$","7,054","","","$","5,498","","","$","5,476","","","$","8.31"]]
[[/GREPCENT_TABLE]]

EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; 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, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

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

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2024","","","2023","","","2022"],["Net earnings (GAAP)","","$","2,942","","","$","3,782","","","$","6,037"],["Financing costs, net","","","363","","","","308","","","","309"],["Income tax expense","","","770","","","","841","","","","1,738"],["Exploration expenses","","","28","","","","20","","","","29"],["Depreciation, depletion and amortization","","","3,255","","","","2,554","","","","2,223"],["Asset dispositions","","","11","","","","(30",")","","","(44",")"],["Share-based compensation","","","98","","","","92","","","","87"],["Derivative and financial instrument non-cash valuation changes","","","176","","","","(71",")","","","(698",")"],["Accretion on discounted liabilities and other","","","96","","","","38","","","","(95",")"],["EBITDAX (Non-GAAP)","","","7,739","","","","7,534","","","","9,586"],["Marketing and midstream revenues and expenses, net","","","49","","","","60","","","","35"],["Commodity derivative cash settlements","","","(197",")","","","(47",")","","","1,356"],["General and administrative expenses, cash-based","","","402","","","","316","","","","308"],["Field-level cash margin (Non-GAAP)","","$","7,993","","","$","7,863","","","$","11,285"]]
[[/GREPCENT_TABLE]]

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