Dividends
Devon pays a quarterly dividend which can be comprised of a fixed dividend and a variable dividend. The variable dividend is dependent on quarterly cash flows, among other factors. Devon has raised its fixed dividend multiple times over the past two calendar years and most recently raised it by 9% from $0.22 to $0.24 per share in the first quarter of 2025. The following table summarizes Devon’s dividends for the first six months of 2025 and 2024, respectively.
|
|
|
|
|
|
|
|
|
Dividends |
|
|
Rate Per Share |
|
2025: |
|
|
|
|
|
First quarter |
$ |
163 |
|
|
$ |
0.24 |
|
Second quarter |
|
156 |
|
|
$ |
0.24 |
|
Total year-to-date |
$ |
319 |
|
|
|
|
2024: |
|
|
|
|
|
First quarter |
$ |
299 |
|
|
$ |
0.44 |
|
Second quarter |
|
223 |
|
|
$ |
0.35 |
|
Total year-to-date (1) |
$ |
522 |
|
|
|
|
(1)During the first six months of 2024, Devon paid variable dividends totaling $241 million in addition to its recurring fixed dividend.
In August 2025, Devon announced a fixed cash dividend in the amount of $0.24 per share for approximately $151 million payable in the third quarter of 2025.
Noncontrolling Interests
The noncontrolling interests’ share of CDM’s net earnings and the contributions from and distributions to the noncontrolling interests are presented as components of equity.
On August 1, 2025, Devon completed the acquisition of all the outstanding noncontrolling interests in CDM for $260 million. As a result of this transaction, Devon owns 100% of the equity interests in CDM. The acquisition of the noncontrolling interests will be accounted for as an equity transaction. Accordingly, the difference between the carrying amount of the noncontrolling interests and the consideration paid will be recognized in Devon's additional paid in capital in the consolidated balance sheet.
17.Commitments and Contingencies
Devon is party to various legal actions arising in connection with its business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, paid royalty proceeds in an untimely manner without including required interest, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. As of June 30, 2025, Devon has accrued approximately $40 million in other current liabilities pertaining to such royalty matters.
Environmental and Climate Change Matters
Devon’s business is subject to numerous federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result
in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon believes that it is in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.
The Company has previously received separate NOVs from the EPA alleging emissions and permitting violations relating to certain of our historic operations in North Dakota, western Texas and New Mexico, respectively. The Company has been engaging with the EPA to resolve each of these matters, and Devon is actively negotiating a draft consent decree with the EPA and the Department of Justice with respect to the North Dakota NOV matter. If finalized, the consent decree may include monetary sanctions and obligations to complete mitigation projects and implement specific injunctive relief. Given that negotiations of the draft consent decree are ongoing and the uncertainty as to the ultimate result of the North Dakota NOV matter, we are currently unable to provide an estimate of potential loss; however, the costs associated with the resolution of the North Dakota NOV matter or any of the other NOV matters could be significant in amount and may include monetary penalties.
Beginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon denies the allegations in these lawsuits and intends to vigorously defend against these claims.
The State of Delaware has filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctive relief. Although Devon cannot predict the ultimate outcome of this matter, Devon denies the allegations asserted in this lawsuit and intends to vigorously defend against these claims.
Other Indemnifications and Legacy Matters
Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities, undertaking other restorative actions or performing requirements under surface agreements in existence at the time of disposition. For example, a predecessor entity of a Devon subsidiary previously sold certain private, state and federal oil and gas leases covering properties in shallow waters off the coast of Louisiana in the Gulf of America. These assets are generally referred to as the East Bay Field. The current operator of the East Bay Field has filed for protection under Chapter 11 of the U.S. Bankruptcy Code and will likely be unable to satisfy the eventual decommissioning obligations associated with the East Bay Field. Other companies in the chain of title of the East Bay Field have also sought bankruptcy protection and will also likely be unable to satisfy the eventual decommissioning obligations associated with the East Bay Field.
In March 2025, Devon received an order from the Department of the Interior, Bureau of Safety and Environmental Enforcement to decommission assets located on certain federal leases in the East Bay Field (the “Federal Assets”). As a result, during the first quarter of 2025, Devon recorded a contingent liability of $125 million within other liabilities in the consolidated balance sheet, reflecting the estimated costs of decommissioning the Federal Assets. The Company expects to be able to access funds available under certain bonds and a cash security account as and when Devon performs and pays these decommissioning obligations. Devon believes the funds will likely cover approximately $100 million of the estimated decommissioning costs for the Federal Assets. Accordingly, during the first quarter of 2025, Devon recorded an approximately $100 million receivable related to these sources of funds within other assets in the consolidated balance sheet. The remaining $25 million difference of the recorded decommissioning obligation and such sources of funds was recognized in the first quarter of 2025 in other, net on the consolidated statement of comprehensive earnings. Devon may also be required to perform or fund decommissioning obligations associated with the East Bay Field under state and federal regulations applicable to predecessor operators beyond amounts accrued. Factors impacting this contingency include, among others: (i) the ultimate outcome of the ongoing bankruptcy proceedings, including with respect to state lease assets included in the East Bay Field, (ii) the actual costs to decommission the Federal Assets relative to the estimates, which are subject to numerous assumptions and uncertainties, and (iii) Devon's ability to successfully access funds under decommissioning bonds and other sources.
As of June 30, 2025, Devon has accrued approximately $200 million of contingent liabilities related to such decommissioning legacy matters, including liabilities associated with the East Bay Field.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations for the three-month and six-month periods ended June 30, 2025 compared to previous periods, and in our financial condition and liquidity since December 31, 2024. For information regarding our critical accounting policies and estimates, see our 2024 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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, providing 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 has allowed us to efficiently expand our oil production and operating scale, creating immediate and long-term, sustainable value to shareholders.
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 the second quarter of 2025:
•Production totaled 841 MBoe/d, exceeding guidance by 3%.
•As of June 30, 2025, completed approximately 78% of our authorized $5.0 billion share repurchase program with approximately 85.4 million of our common shares purchased for approximately $3.9 billion, or $45.62 per share since inception of the plan.
•Exited with $4.8 billion of liquidity, including $1.8 billion of cash.
•Generated $1.5 billion of operating cash flow and $6.8 billion for the past twelve trailing months.
•Received $372 million of cash proceeds from the sale of our investment in Matterhorn.
•Paid dividends of $156 million and have declared approximately $151 million of dividends to be paid in the third quarter of 2025.
•Earnings attributable to Devon were $899 million, or $1.41 per diluted share.
•Core earnings (Non-GAAP) were $536 million, or $0.84 per diluted share.
Our net earnings and operating cash flow are highly dependent upon oil, gas and NGL prices which can be volatile due to several varying factors. During the first six months of 2025, commodity prices have experienced heightened volatility and declines, driven primarily by economic uncertainty in global trade arising from geopolitical events and shifting trade policies, such as the imposition of tariffs by the U.S. and planned oil output increases by OPEC+. Despite the potential negative impacts of higher inflation rates and supply chain disruptions created by these developments, we remain committed to capital discipline and delivering the objectives that underpin our current plan. Our disciplined, returns-driven strategy is designed to adapt to market fluctuations by reducing activity when necessary to maximize free cash flow generation. We will continue to 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.
To emphasize our commitment to maximizing free cash flow and creating value for shareholders, we announced a business optimization plan which is anticipated to improve our annual pre-tax cash flow by $1.0 billion. The plan includes actions to achieve more efficient field-level operations and improvements in drilling and completion costs while improving operating margins and corporate costs. These savings are on track to be achieved by the end of 2026 with approximately $400 million expected to be completed by the end of 2025.
Results of Operations
The following graphs, 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 noncontrolling interests.
Q2 2025 vs. Q1 2025
Our second quarter 2025 and first quarter 2025 net earnings were $917 million and $509 million, respectively. The graph below shows the change in net earnings from the first quarter of 2025 to the second quarter of 2025. The material changes are further discussed by category on the following pages.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
228 |
|
|
|
59 |
% |
|
|
216 |
|
|
|
5 |
% |
Rockies |
|
|
104 |
|
|
|
27 |
% |
|
|
112 |
|
|
|
-7 |
% |
Eagle Ford |
|
|
39 |
|
|
|
10 |
% |
|
|
45 |
|
|
|
-12 |
% |
Anadarko Basin |
|
|
13 |
|
|
|
3 |
% |
|
|
11 |
|
|
|
9 |
% |
Other |
|
|
3 |
|
|
|
1 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
387 |
|
|
|
100 |
% |
|
|
388 |
|
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
823 |
|
|
|
59 |
% |
|
|
744 |
|
|
|
11 |
% |
Rockies |
|
|
228 |
|
|
|
16 |
% |
|
|
233 |
|
|
|
-2 |
% |
Eagle Ford |
|
|
62 |
|
|
|
5 |
% |
|
|
117 |
|
|
|
-47 |
% |
Anadarko Basin |
|
|
274 |
|
|
|
20 |
% |
|
|
252 |
|
|
|
9 |
% |
Other |
|
|
1 |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
1,388 |
|
|
|
100 |
% |
|
|
1,346 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
133 |
|
|
|
60 |
% |
|
|
118 |
|
|
|
13 |
% |
Rockies |
|
|
47 |
|
|
|
21 |
% |
|
|
44 |
|
|
|
6 |
% |
Eagle Ford |
|
|
11 |
|
|
|
5 |
% |
|
|
15 |
|
|
|
-29 |
% |
Anadarko Basin |
|
|
31 |
|
|
|
14 |
% |
|
|
26 |
|
|
|
21 |
% |
Other |
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
222 |
|
|
|
100 |
% |
|
|
203 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
498 |
|
|
|
59 |
% |
|
|
458 |
|
|
|
9 |
% |
Rockies |
|
|
189 |
|
|
|
23 |
% |
|
|
195 |
|
|
|
-3 |
% |
Eagle Ford |
|
|
60 |
|
|
|
7 |
% |
|
|
79 |
|
|
|
-24 |
% |
Anadarko Basin |
|
|
90 |
|
|
|
11 |
% |
|
|
79 |
|
|
|
14 |
% |
Other |
|
|
4 |
|
|
|
0 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
841 |
|
|
|
100 |
% |
|
|
815 |
|
|
|
3 |
% |
From the first quarter of 2025 to the second quarter of 2025, the change in volumes contributed to a $78 million increase in earnings. The increase in volumes was primarily due to new well activity in the Delaware and Anadarko Basins.
Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
63.95 |
|
|
|
|
$ |
71.50 |
|
|
|
-11 |
% |
Realized price, unhedged |
|
$ |
61.70 |
|
|
96% |
|
$ |
69.13 |
|
|
|
-11 |
% |
Cash settlements |
|
$ |
1.27 |
|
|
|
|
$ |
0.02 |
|
|
|
|
Realized price, with hedges |
|
$ |
62.97 |
|
|
98% |
|
$ |
69.15 |
|
|
|
-9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
|
$ |
3.44 |
|
|
|
|
$ |
3.65 |
|
|
|
-6 |
% |
Realized price, unhedged |
|
$ |
1.41 |
|
|
41% |
|
$ |
2.55 |
|
|
|
-45 |
% |
Cash settlements |
|
$ |
0.15 |
|
|
|
|
$ |
(0.07 |
) |
|
|
|
Realized price, with hedges |
|
$ |
1.56 |
|
|
45% |
|
$ |
2.48 |
|
|
|
-37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
63.95 |
|
|
|
|
$ |
71.50 |
|
|
|
-11 |
% |
Realized price, unhedged |
|
$ |
17.71 |
|
|
28% |
|
$ |
22.03 |
|
|
|
-20 |
% |
Cash settlements |
|
$ |
0.11 |
|
|
|
|
$ |
(0.10 |
) |
|
|
|
Realized price, with hedges |
|
$ |
17.82 |
|
|
28% |
|
$ |
21.93 |
|
|
|
-19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
|
$ |
35.43 |
|
|
$ |
42.58 |
|
|
|
-17 |
% |
Cash settlements |
|
$ |
0.87 |
|
|
$ |
(0.13 |
) |
|
|
|
Realized price, with hedges |
|
$ |
36.30 |
|
|
$ |
42.45 |
|
|
|
-14 |
% |
From the first quarter of 2025 to the second quarter of 2025, realized prices contributed to a $494 million decrease in earnings. Unhedged oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices, respectively. The decrease in unhedged prices was partially offset by oil, gas and NGL hedge cash settlements.
We currently have approximately 30% and 35% of our remaining anticipated 2025 oil and gas production hedged, respectively. For 2026, we currently have approximately 20% and 30% of our anticipated oil and gas production hedged, respectively.
Hedge Settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change |
|
|
Q |
|
|
|
|
|
|
Oil |
|
$ |
45 |
|
|
$ |
— |
|
|
N/M |
Natural gas |
|
|
20 |
|
|
|
(8 |
) |
|
N/M |
NGL |
|
|
2 |
|
|
|
(2 |
) |
|
N/M |
Total cash settlements (1) |
|
$ |
67 |
|
|
$ |
(10 |
) |
|
N/M |
(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 “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change |
|
LOE |
|
$ |
483 |
|
|
$ |
479 |
|
|
|
1 |
% |
Gathering, processing & transportation |
|
|
219 |
|
|
|
204 |
|
|
|
7 |
% |
Production taxes |
|
|
180 |
|
|
|
212 |
|
|
|
-15 |
% |
Property taxes |
|
|
17 |
|
|
|
17 |
|
|
|
0 |
% |
Total |
|
$ |
899 |
|
|
$ |
912 |
|
|
|
-1 |
% |
Per Boe: |
|
|
|
|
|
|
|
|
|
LOE |
|
$ |
6.31 |
|
|
$ |
6.53 |
|
|
|
-3 |
% |
Gathering, processing & transportation |
|
$ |
2.86 |
|
|
$ |
2.78 |
|
|
|
3 |
% |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
6.6 |
% |
|
|
6.8 |
% |
|
|
-2 |
% |
Production expenses decreased in the second quarter of 2025 primarily due to lower production taxes resulting from lower commodity prices.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
$ per BOE |
|
|
Q1 2025 |
|
|
$ per BOE |
|
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
$ |
1,114 |
|
|
$ |
24.58 |
|
|
$ |
1,283 |
|
|
$ |
31.13 |
|
Rockies |
|
|
369 |
|
|
$ |
21.45 |
|
|
|
509 |
|
|
$ |
29.01 |
|
Eagle Ford |
|
|
197 |
|
|
$ |
35.84 |
|
|
|
270 |
|
|
$ |
37.98 |
|
Anadarko Basin |
|
|
121 |
|
|
$ |
14.85 |
|
|
|
136 |
|
|
$ |
19.13 |
|
Other |
|
|
10 |
|
|
N/M |
|
|
|
16 |
|
|
N/M |
|
Total |
|
$ |
1,811 |
|
|
$ |
23.68 |
|
|
$ |
2,214 |
|
|
$ |
30.16 |
|
DD&A and Asset Impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change |
|
Oil and gas per Boe |
|
$ |
11.63 |
|
|
$ |
12.07 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
Oil and gas |
|
$ |
890 |
|
|
$ |
886 |
|
|
|
0 |
% |
Other property and equipment |
|
|
24 |
|
|
|
26 |
|
|
|
-9 |
% |
Total DD&A |
|
$ |
914 |
|
|
$ |
912 |
|
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
Asset impairments |
|
$ |
— |
|
|
$ |
254 |
|
|
N/M |
|
In the first quarter of 2025, Devon rationalized two headquarters-related real estate assets resulting in total asset impairments of $254 million. See Note 5 in "Part I. Financial Information – Item 1. Financial Statements" of this report for further discussion.
G&A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change |
|
G&A per Boe |
|
$ |
1.47 |
|
|
$ |
1.77 |
|
|
|
-17 |
% |
|
|
|
|
|
|
|
|
|
|
Labor and benefits |
|
$ |
56 |
|
|
$ |
70 |
|
|
|
-20 |
% |
Non-labor |
|
|
57 |
|
|
|
60 |
|
|
|
-5 |
% |
Total |
|
$ |
113 |
|
|
$ |
130 |
|
|
|
-13 |
% |
G&A costs were lower in the second quarter of 2025 primarily due to lower labor and benefit costs.
Other Items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
|
Change in earnings |
|
Commodity hedge valuation changes (1) |
|
$ |
169 |
|
|
$ |
(88 |
) |
|
$ |
257 |
|
Marketing and midstream operations |
|
|
(19 |
) |
|
|
(12 |
) |
|
|
(7 |
) |
Exploration expenses |
|
|
20 |
|
|
|
10 |
|
|
|
(10 |
) |
Asset dispositions |
|
|
(307 |
) |
|
|
2 |
|
|
|
309 |
|
Net financing costs |
|
|
116 |
|
|
|
123 |
|
|
|
7 |
|
Other, net |
|
|
11 |
|
|
|
27 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
$ |
572 |
|
(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. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
During the second quarter of 2025, Devon sold its investment in Matterhorn for $372 million and recognized a pre-tax gain of $307 million ($239 million, net of tax), which was recorded to asset dispositions. The monetization of this investment will not change the terms or conditions of Devon's secured capacity on the pipeline. For additional information, see Note 12 in "Part I. Financial Information - Item 1. Financial Statements" in this report.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Q2 2025 |
|
|
Q1 2025 |
|
Current expense |
|
$ |
226 |
|
|
$ |
96 |
|
Deferred expense |
|
|
18 |
|
|
|
41 |
|
Total expense |
|
$ |
244 |
|
|
$ |
137 |
|
Current tax rate |
|
|
19 |
% |
|
|
15 |
% |
Deferred tax rate |
|
|
2 |
% |
|
|
6 |
% |
Effective income tax rate |
|
|
21 |
% |
|
|
21 |
% |
Following the enactment of the OBBB on July 4, 2025, we anticipate our current tax rates will be lower beginning in the third quarter of 2025 and will continue through the remainder of 2025 and future periods. For additional information on income taxes, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
June 30, 2025 YTD vs. June 30, 2024 YTD
Our six months ended June 30, 2025 net earnings were $1.4 billion, compared to net earnings of $1.5 billion for the first six months ended June 30, 2024. The graph below shows the change in net earnings from the six months ended June 30, 2024 to the six months ended June 30, 2025. The material changes are further discussed by category on the following pages.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
% of Total |
|
|
2024 |
|
|
Change |
|
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
222 |
|
|
|
57 |
% |
|
|
215 |
|
|
|
3 |
% |
Rockies |
|
|
108 |
|
|
|
28 |
% |
|
|
52 |
|
|
|
109 |
% |
Eagle Ford |
|
|
42 |
|
|
|
11 |
% |
|
|
45 |
|
|
|
-6 |
% |
Anadarko Basin |
|
|
12 |
|
|
|
3 |
% |
|
|
12 |
|
|
|
-2 |
% |
Other |
|
|
4 |
|
|
|
1 |
% |
|
|
3 |
|
|
N/M |
|
Total |
|
|
388 |
|
|
|
100 |
% |
|
|
327 |
|
|
|
18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
% of Total |
|
|
2024 |
|
|
Change |
|
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
784 |
|
|
|
57 |
% |
|
|
703 |
|
|
|
11 |
% |
Rockies |
|
|
230 |
|
|
|
17 |
% |
|
|
85 |
|
|
|
171 |
% |
Eagle Ford |
|
|
89 |
|
|
|
7 |
% |
|
|
86 |
|
|
|
4 |
% |
Anadarko Basin |
|
|
263 |
|
|
|
19 |
% |
|
|
233 |
|
|
|
13 |
% |
Other |
|
|
1 |
|
|
|
0 |
% |
|
|
1 |
|
|
N/M |
|
Total |
|
|
1,367 |
|
|
|
100 |
% |
|
|
1,108 |
|
|
|
23 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
% of Total |
|
|
2024 |
|
|
Change |
|
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
126 |
|
|
|
59 |
% |
|
|
117 |
|
|
|
8 |
% |
Rockies |
|
|
46 |
|
|
|
22 |
% |
|
|
13 |
|
|
|
245 |
% |
Eagle Ford |
|
|
13 |
|
|
|
6 |
% |
|
|
16 |
|
|
|
-17 |
% |
Anadarko Basin |
|
|
28 |
|
|
|
13 |
% |
|
|
28 |
|
|
|
2 |
% |
Other |
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
213 |
|
|
|
100 |
% |
|
|
174 |
|
|
|
23 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
% of Total |
|
|
2024 |
|
|
Change |
|
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
478 |
|
|
|
58 |
% |
|
|
449 |
|
|
|
7 |
% |
Rockies |
|
|
192 |
|
|
|
23 |
% |
|
|
79 |
|
|
|
143 |
% |
Eagle Ford |
|
|
70 |
|
|
|
8 |
% |
|
|
75 |
|
|
|
-7 |
% |
Anadarko Basin |
|
|
84 |
|
|
|
10 |
% |
|
|
79 |
|
|
|
7 |
% |
Other |
|
|
4 |
|
|
|
1 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
828 |
|
|
|
100 |
% |
|
|
686 |
|
|
|
21 |
% |
From the six months ended June 30, 2024 to the six months ended June 30, 2025, the change in volumes contributed to a $1.0 billion increase in earnings. Volumes increased primarily due to the Grayson Mill acquisition in the Rockies, which closed in the third quarter of 2024, as well as new well activity in the Delaware and Anadarko Basins.
Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
Realization |
|
2024 |
|
|
Change |
|
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
67.72 |
|
|
|
|
$ |
78.82 |
|
|
|
-14 |
% |
Realized price, unhedged |
|
$ |
65.40 |
|
|
97% |
|
$ |
77.30 |
|
|
|
-15 |
% |
Cash settlements |
|
$ |
0.64 |
|
|
|
|
$ |
(0.20 |
) |
|
|
|
Realized price, with hedges |
|
$ |
66.04 |
|
|
98% |
|
$ |
77.10 |
|
|
|
-14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
Realization |
|
2024 |
|
|
Change |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
|
$ |
3.55 |
|
|
|
|
$ |
2.07 |
|
|
|
71 |
% |
Realized price, unhedged |
|
$ |
1.97 |
|
|
55% |
|
$ |
0.92 |
|
|
|
115 |
% |
Cash settlements |
|
$ |
0.04 |
|
|
|
|
$ |
0.44 |
|
|
|
|
Realized price, with hedges |
|
$ |
2.01 |
|
|
57% |
|
$ |
1.36 |
|
|
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
Realization |
|
2024 |
|
|
Change |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
67.72 |
|
|
|
|
$ |
78.82 |
|
|
|
-14 |
% |
Realized price, unhedged |
|
$ |
19.76 |
|
|
29% |
|
$ |
20.17 |
|
|
|
-2 |
% |
Cash settlements |
|
$ |
0.01 |
|
|
|
|
$ |
0.02 |
|
|
|
|
Realized price, with hedges |
|
$ |
19.77 |
|
|
29% |
|
$ |
20.19 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
|
$ |
38.93 |
|
|
$ |
43.48 |
|
|
|
-10 |
% |
Cash settlements |
|
$ |
0.38 |
|
|
$ |
0.62 |
|
|
|
|
Realized price, with hedges |
|
$ |
39.31 |
|
|
$ |
44.10 |
|
|
|
-11 |
% |
From the six months ended June 30, 2024 to the six months ended June 30, 2025, realized prices contributed to a $590 million decrease in earnings. This decrease was primarily due to lower unhedged realized oil prices which decreased primarily due to a lower WTI index price. This decrease was partially offset by an increase in unhedged realized gas prices which was primarily due to higher Henry Hub index prices. Realized prices were also positively impacted by oil and gas hedge cash settlements.
Hedge Settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change |
|
Oil |
|
$ |
45 |
|
|
$ |
(12 |
) |
|
N/M |
|
Natural gas |
|
|
12 |
|
|
|
89 |
|
|
N/M |
|
NGL |
|
|
— |
|
|
|
1 |
|
|
N/M |
|
Total cash settlements (1) |
|
$ |
57 |
|
|
$ |
78 |
|
|
|
-27 |
% |
(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 “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change |
|
LOE |
|
$ |
962 |
|
|
$ |
763 |
|
|
|
26 |
% |
Gathering, processing & transportation |
|
|
423 |
|
|
|
377 |
|
|
|
12 |
% |
Production taxes |
|
|
392 |
|
|
|
363 |
|
|
|
8 |
% |
Property taxes |
|
|
34 |
|
|
|
36 |
|
|
|
-6 |
% |
Total |
|
$ |
1,811 |
|
|
$ |
1,539 |
|
|
|
18 |
% |
Per Boe: |
|
|
|
|
|
|
|
|
|
LOE |
|
$ |
6.42 |
|
|
$ |
6.12 |
|
|
|
5 |
% |
Gathering, processing & transportation |
|
$ |
2.82 |
|
|
$ |
3.02 |
|
|
|
-7 |
% |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
6.7 |
% |
|
|
6.7 |
% |
|
|
0 |
% |
Production expenses increased in the first six months of 2025 primarily due to increased activity in the Rockies related to the Grayson Mill acquisition in addition to new well activity in the Delaware Basin.
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 sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
$ per BOE |
|
|
2024 |
|
|
$ per BOE |
|
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
$ |
2,397 |
|
|
$ |
27.70 |
|
|
$ |
2,621 |
|
|
$ |
32.09 |
|
Rockies |
|
|
878 |
|
|
$ |
25.27 |
|
|
|
448 |
|
|
$ |
31.14 |
|
Eagle Ford |
|
|
467 |
|
|
$ |
37.05 |
|
|
|
570 |
|
|
$ |
41.99 |
|
Anadarko Basin |
|
|
257 |
|
|
$ |
16.85 |
|
|
|
217 |
|
|
$ |
15.09 |
|
Other |
|
|
26 |
|
|
N/M |
|
|
|
30 |
|
|
N/M |
|
Total |
|
$ |
4,025 |
|
|
$ |
26.85 |
|
|
$ |
3,886 |
|
|
$ |
31.14 |
|
DD&A and Asset Impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change |
|
Oil and gas per Boe |
|
$ |
11.85 |
|
|
$ |
11.56 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
Oil and gas |
|
$ |
1,776 |
|
|
$ |
1,443 |
|
|
|
23 |
% |
Other property and equipment |
|
|
50 |
|
|
|
47 |
|
|
|
8 |
% |
Total DD&A |
|
$ |
1,826 |
|
|
$ |
1,490 |
|
|
|
23 |
% |
|
|
|
|
|
|
|
|
|
|
Asset impairments |
|
$ |
254 |
|
|
$ |
— |
|
|
N/M |
|
DD&A increased in the first six months of 2025 primarily due to higher volumes driven by the Grayson Mill acquisition and new well activity in the Delaware Basin.
In the first quarter of 2025, Devon rationalized two headquarters-related real estate assets resulting in total asset impairments of $254 million. See Note 5 in "Part I. Financial Information – Item 1. Financial Statements" of this report for further discussion.
G&A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change |
|
G&A per Boe |
|
$ |
1.62 |
|
|
$ |
1.83 |
|
|
|
-12 |
% |
|
|
|
|
|
|
|
|
|
|
Labor and benefits |
|
$ |
126 |
|
|
$ |
125 |
|
|
|
1 |
% |
Non-labor |
|
|
117 |
|
|
|
103 |
|
|
|
14 |
% |
Total |
|
$ |
243 |
|
|
$ |
228 |
|
|
|
7 |
% |
While our G&A increased in the first six months of 2025, our G&A per BOE rate has decreased due to the Grayson Mill acquisition efficiently expanding our operating scale and production.
Other Items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
Change in earnings |
|
Commodity hedge valuation changes (1) |
|
$ |
81 |
|
|
$ |
(200 |
) |
|
$ |
281 |
|
Marketing and midstream operations |
|
|
(31 |
) |
|
|
(31 |
) |
|
|
- |
|
Exploration expenses |
|
|
30 |
|
|
|
12 |
|
|
|
(18 |
) |
Asset dispositions |
|
|
(305 |
) |
|
|
16 |
|
|
|
321 |
|
Net financing costs |
|
|
239 |
|
|
|
152 |
|
|
|
(87 |
) |
Other, net |
|
|
38 |
|
|
|
27 |
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
$ |
486 |
|
(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. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in 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. For additional information, see Note 13 in "Part I. Financial Information - Item 1. Financial Statements" in this report.
During the second quarter of 2025, Devon sold its investment in Matterhorn for $372 million and recognized a pre-tax gain of $307 million ($239 million, net of tax), which was recorded to asset dispositions. The monetization of this investment will not change the terms or conditions of Devon's secured capacity on the pipeline. For additional information, see Note 12 in "Part I. Financial Information - Item 1. Financial Statements" in this report.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
Current expense |
|
$ |
322 |
|
|
$ |
265 |
|
Deferred expense |
|
|
59 |
|
|
|
79 |
|
Total expense |
|
$ |
381 |
|
|
$ |
344 |
|
Current tax rate |
|
|
18 |
% |
|
|
15 |
% |
Deferred tax rate |
|
|
3 |
% |
|
|
4 |
% |
Effective income tax rate |
|
|
21 |
% |
|
|
19 |
% |
Following the enactment of the OBBB on July 4, 2025, we anticipate our current tax rates will be lower beginning in the third quarter of 2025 and will continue through the remainder of 2025 and future periods. For information on income taxes, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in 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 three and six months ended June 30, 2025 and 2024.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
2025 |
|
|
2024 |
|
Operating cash flow |
|
$ |
1,545 |
|
|
$ |
1,535 |
|
|
$ |
3,487 |
|
|
$ |
3,273 |
|
Capital expenditures |
|
|
(956 |
) |
|
|
(948 |
) |
|
|
(1,890 |
) |
|
|
(1,842 |
) |
Acquisitions of property and equipment |
|
|
(16 |
) |
|
|
(82 |
) |
|
|
(24 |
) |
|
|
(90 |
) |
Divestitures of property, equipment and investments |
|
|
372 |
|
|
|
1 |
|
|
|
505 |
|
|
|
18 |
|
Investment activity, net |
|
|
3 |
|
|
|
10 |
|
|
|
10 |
|
|
|
(26 |
) |
Repurchases of common stock |
|
|
(249 |
) |
|
|
(256 |
) |
|
|
(550 |
) |
|
|
(461 |
) |
Common stock dividends |
|
|
(156 |
) |
|
|
(223 |
) |
|
|
(319 |
) |
|
|
(522 |
) |
Noncontrolling interest activity, net |
|
|
(14 |
) |
|
|
(7 |
) |
|
|
(9 |
) |
|
|
(2 |
) |
Repayment of finance lease |
|
|
— |
|
|
|
— |
|
|
|
(274 |
) |
|
|
— |
|
Other |
|
|
(4 |
) |
|
|
(10 |
) |
|
|
(23 |
) |
|
|
(54 |
) |
Net change in cash, cash equivalents and restricted cash |
|
$ |
525 |
|
|
$ |
20 |
|
|
$ |
913 |
|
|
$ |
294 |
|
Cash, cash equivalents and restricted cash at end of period |
|
$ |
1,759 |
|
|
$ |
1,169 |
|
|
$ |
1,759 |
|
|
$ |
1,169 |
|
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 share repurchases and dividends.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
2025 |
|
|
2024 |
|
Delaware Basin |
|
$ |
488 |
|
|
$ |
539 |
|
|
$ |
956 |
|
|
$ |
1,073 |
|
Rockies |
|
|
233 |
|
|
|
95 |
|
|
|
455 |
|
|
|
170 |
|
Eagle Ford |
|
|
142 |
|
|
|
202 |
|
|
|
293 |
|
|
|
359 |
|
Anadarko Basin |
|
|
39 |
|
|
|
59 |
|
|
|
84 |
|
|
|
119 |
|
Other |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
Total oil and gas |
|
|
903 |
|
|
|
896 |
|
|
|
1,790 |
|
|
|
1,724 |
|
Midstream |
|
|
34 |
|
|
|
30 |
|
|
|
66 |
|
|
|
67 |
|
Other |
|
|
19 |
|
|
|
22 |
|
|
|
34 |
|
|
|
51 |
|
Total capital expenditures |
|
$ |
956 |
|
|
$ |
948 |
|
|
$ |
1,890 |
|
|
$ |
1,842 |
|
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 the first six months of 2025 represented approximately 54% of our operating cash flow.
Divestitures of Property, Equipment and Investments
During the first six months of 2025, we generated additional cash flow by monetizing our investment in Matterhorn for $372 million and divesting headquarters-related real estate assets for $134 million as part of our real estate rationalization initiatives. These proceeds will be used to further strengthen our investment-grade financial position. For additional information regarding these divestitures, see Note 12 and Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
During the first six months of 2025 and 2024, we received $20 million in contingent earnout payments related to assets previously sold. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Investment Activity
During the first six months of 2025 and 2024, we received distributions from our investments of $20 million and $22 million, respectively. We contributed $10 million and $48 million to our investments during the first six months of 2025 and 2024, respectively.
Shareholder Distributions and Stock Activity
We repurchased approximately 16.4 million shares of common stock for $550 million and approximately 9.6 million shares of common stock for $449 million under the share repurchase program authorized by our Board of Directors in the first six months of 2025 and 2024, respectively. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The following table summarizes our common stock dividends during the second quarter and total for the first six months of 2025 and 2024. Devon most recently raised its fixed dividend by 9% from $0.22 to $0.24 per share in the first quarter of 2025.
|
|
|
|
|
|
|
|
|
Dividends |
|
|
Rate Per Share |
|
2025: |
|
|
|
|
|
First quarter |
$ |
163 |
|
|
$ |
0.24 |
|
Second quarter |
|
156 |
|
|
$ |
0.24 |
|
Total year-to-date |
$ |
319 |
|
|
|
|
2024: |
|
|
|
|
|
First quarter |
$ |
299 |
|
|
$ |
0.44 |
|
Second quarter |
|
223 |
|
|
$ |
0.35 |
|
Total year-to-date (1) |
$ |
522 |
|
|
|
|
(1)In the first six months of 2024, Devon paid variable dividends totaling $241 million in addition to its recurring fixed dividend.
Noncontrolling Interest Activity, net
During the first six months of 2025 and 2024, we distributed $23 million and $26 million, respectively, to our noncontrolling interests in CDM. During the first six months of 2025 and 2024, we received $14 million and $24 million, respectively, in contributions from our noncontrolling interests.
Repayment of Finance Lease
During the first six months of 2025, we paid $274 million in cash to extinguish a financing lease related to a headquarters-related real estate asset as part of our real estate rationalization initiatives. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
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 landowners to enhance our existing portfolio of assets.
On September 27, 2024, Devon acquired the Williston Basin business of Grayson Mill. This acquisition added a high-margin production mix that has enhanced our position and efficiently expanded our operating scale and production. The acquisition continues to deliver 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.
To emphasize our commitment to maximizing free cash flow and creating value for shareholders, we recently announced a business optimization plan which is anticipated to improve our annual pre-tax cash flow by $1.0 billion. These optimization initiatives will be primarily focused on capital efficiencies, production optimization, commercial opportunities and corporate cost reductions. These savings are on track to be achieved by the end of 2026 with approximately $400 million expected to be completed by the end of 2025.
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 return cash to shareholders.
Operating Cash Flow
Key inputs into determining our planned capital investment are 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 the second quarter of 2025, we held approximately $1.8 billion of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.
Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, changes in public policy, including the imposition of tariffs by the U.S. or other countries, 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 June 30, 2025 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” of this report.
Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. We remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2025. However, if commodity prices decline further, we will adapt our plan by reducing activity in order to maximize free cash flow.
Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.
Additionally, the economic uncertainty in global trade arising from geopolitical events and shifting trade policies, such as the imposition of tariffs by the U.S., may contribute to higher inflation rates and disrupt supply chains, negatively impacting our cash flow. While we actively work to mitigate the impact of these potential risks through operational efficiencies gained from the scale of our operations as well as by leveraging long-standing relationships with our suppliers, the ultimate impacts remain uncertain.
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 our 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 cash collateral postings.
Credit Availability
As of June 30, 2025, we had approximately $3.0 billion of available borrowing capacity under our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At June 30, 2025, there were no borrowings under our commercial paper program, and we were in compliance with the Senior Credit Facility’s financial covenant.
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 the 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 our Term Loan or 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 August 2025, Devon announced a cash dividend in the amount of $0.24 per share payable in the third quarter of 2025 and will total approximately $151 million.
Our Board of Directors has authorized a $5.0 billion share repurchase program that expires on June 30, 2026. Through July 2025, we had executed $4.0 billion of the authorized program.
Capital Expenditures
Our capital expenditures budget for the remainder of 2025 is expected to be approximately $1.7 billion to $1.9 billion.
Acquisition of Noncontrolling Interests in CDM
On August 1, 2025, Devon completed the acquisition of all the outstanding noncontrolling interests in CDM for $260 million. Following this transaction, we will no longer distribute a portion of CDM’s cash flows to noncontrolling interest holders.
Critical Accounting Estimates
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.
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 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.
For additional information regarding our critical accounting policies and estimates, see our 2024 Annual Report on Form 10-K.
Non-GAAP Measures
We utilize “core earnings attributable to Devon” and “core earnings per share attributable to Devon” 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 non-cash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, non-cash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance, fair value changes in derivative financial instruments and restructuring and transaction costs.
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 core earnings and core earnings per share attributable to Devon to comparable GAAP measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
Before Tax |
|
|
After Tax |
|
|
After NCI |
|
|
Per Diluted Share |
|
|
Before Tax |
|
|
After Tax |
|
|
After NCI |
|
|
Per Diluted Share |
|
2025: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) |
$ |
1,161 |
|
|
$ |
917 |
|
|
$ |
899 |
|
|
$ |
1.41 |
|
|
$ |
1,807 |
|
|
$ |
1,426 |
|
|
$ |
1,393 |
|
|
$ |
2.17 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
|
(307 |
) |
|
|
(239 |
) |
|
|
(239 |
) |
|
|
(0.38 |
) |
|
|
(305 |
) |
|
|
(238 |
) |
|
|
(238 |
) |
|
|
(0.37 |
) |
Asset and exploration impairments |
|
4 |
|
|
|
2 |
|
|
|
2 |
|
|
|
0.01 |
|
|
|
263 |
|
|
|
204 |
|
|
|
204 |
|
|
|
0.32 |
|
Fair value changes in financial instruments |
|
(172 |
) |
|
|
(133 |
) |
|
|
(133 |
) |
|
|
(0.21 |
) |
|
|
(84 |
) |
|
|
(65 |
) |
|
|
(65 |
) |
|
|
(0.10 |
) |
Restructuring and transaction costs |
|
9 |
|
|
|
7 |
|
|
|
7 |
|
|
|
0.01 |
|
|
|
27 |
|
|
|
21 |
|
|
|
21 |
|
|
|
0.03 |
|
Core earnings attributable to Devon (Non-GAAP) |
$ |
695 |
|
|
$ |
554 |
|
|
$ |
536 |
|
|
$ |
0.84 |
|
|
$ |
1,708 |
|
|
$ |
1,348 |
|
|
$ |
1,315 |
|
|
$ |
2.05 |
|
2024: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) |
$ |
1,040 |
|
|
$ |
855 |
|
|
$ |
844 |
|
|
$ |
1.34 |
|
|
$ |
1,808 |
|
|
$ |
1,464 |
|
|
$ |
1,440 |
|
|
$ |
2.29 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
|
15 |
|
|
|
11 |
|
|
|
11 |
|
|
|
0.02 |
|
|
|
16 |
|
|
|
12 |
|
|
|
12 |
|
|
|
0.02 |
|
Asset and exploration impairments |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
— |
|
Deferred tax asset valuation allowance |
|
— |
|
|
|
4 |
|
|
|
4 |
|
|
|
0.01 |
|
|
|
— |
|
|
|
3 |
|
|
|
3 |
|
|
|
— |
|
Fair value changes in financial instruments |
|
32 |
|
|
|
25 |
|
|
|
25 |
|
|
|
0.04 |
|
|
|
204 |
|
|
|
159 |
|
|
|
159 |
|
|
|
0.25 |
|
Core earnings attributable to Devon (Non-GAAP) |
$ |
1,088 |
|
|
$ |
896 |
|
|
$ |
885 |
|
|
$ |
1.41 |
|
|
$ |
2,029 |
|
|
$ |
1,639 |
|
|
$ |
1,615 |
|
|
$ |
2.56 |
|
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL sales less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2025 |
|
|
2024 |
|
|
2025 |
|
|
2024 |
|
Net earnings (GAAP) |
|
$ |
917 |
|
|
$ |
855 |
|
|
$ |
1,426 |
|
|
$ |
1,464 |
|
Financing costs, net |
|
|
116 |
|
|
|
76 |
|
|
|
239 |
|
|
|
152 |
|
Income tax expense |
|
|
244 |
|
|
|
185 |
|
|
|
381 |
|
|
|
344 |
|
Exploration expenses |
|
|
20 |
|
|
|
3 |
|
|
|
30 |
|
|
|
12 |
|
Depreciation, depletion and amortization |
|
|
914 |
|
|
|
768 |
|
|
|
1,826 |
|
|
|
1,490 |
|
Asset impairments |
|
|
— |
|
|
|
— |
|
|
|
254 |
|
|
|
— |
|
Asset dispositions |
|
|
(307 |
) |
|
|
15 |
|
|
|
(305 |
) |
|
|
16 |
|
Share-based compensation |
|
|
22 |
|
|
|
26 |
|
|
|
46 |
|
|
|
50 |
|
Derivative and financial instrument non-cash valuation changes |
|
|
(169 |
) |
|
|
31 |
|
|
|
(81 |
) |
|
|
200 |
|
Accretion on discounted liabilities and other |
|
|
11 |
|
|
|
5 |
|
|
|
38 |
|
|
|
27 |
|
EBITDAX (Non-GAAP) |
|
|
1,768 |
|
|
|
1,964 |
|
|
|
3,854 |
|
|
|
3,755 |
|
Marketing and midstream revenues and expenses, net |
|
|
19 |
|
|
|
10 |
|
|
|
31 |
|
|
|
31 |
|
Commodity derivative cash settlements |
|
|
(67 |
) |
|
|
(54 |
) |
|
|
(57 |
) |
|
|
(78 |
) |
General and administrative expenses, cash-based |
|
|
91 |
|
|
|
88 |
|
|
|
197 |
|
|
|
178 |
|
Field-level cash margin (Non-GAAP) |
|
$ |
1,811 |
|
|
$ |
2,008 |
|
|
$ |
4,025 |
|
|
$ |
3,886 |
|
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
As of June 30, 2025, we have commodity derivatives that pertain to a portion of our estimated production for the last six months of 2025, as well as for 2026 and 2027. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At June 30, 2025, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $270 million.
Interest Rate Risk
At June 30, 2025, we had total debt of $8.9 billion. Of this debt, $7.9 billion was comprised of debentures and notes that have fixed interest rates which averaged 5.7%. We also have a $1.0 billion Term Loan which has a variable interest rate that is adjusted monthly. The interest rate on the Term Loan was 5.8% at June 30, 2025.
Item 4. Controls and Procedures
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 June 30, 2025 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.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
