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    Devon Energy Corporation

    405 552 4702 Phone

    20 North Broadway

    405 552 7692 Fax

    Oklahoma City, OK 73102-8260

    danny.heatly@dvn.com

April 14, 2010

Via EDGAR and Facsimile No. 703 813 6982

Attention: Mr. Bob Carroll, Division of Corporation Finance

H. Roger Schwall

Assistant Director

U.S. Securities and Exchange Commission

100 F. Street, N.E.

Washington, D.C. 20549-7010

    Re:

    Devon Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2009

Filed February 25, 2010

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated March 31, 2010, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2009, filed February 25, 2010 (File No.
1-32318). Devon’s responses to the staff’s comments are set forth below:

General

SEC Comment

    1.

    We note your March 11, 2010 press release announcing that you have entered into agreements to
sell all of your assets in the deepwater Gulf of Mexico, Brazil and Azerbaijan to BP for $7.0
billion, that BP will assume your leases of the Seadrill West Sirius and Transocean Deepwater
Discovery drilling rigs for the duration of the contract terms, and that you and BP will form
a heavy oil joint venture to develop BP’s Kirby oil sands leases in Alberta, Canada. However,
it does not appear that you filed a Form 8-K with regard to these developments. Please
explain to us your analysis as to whether a Form 8-K filing was required.

Response

Prior to issuing our press release on March 11, 2010, we considered the requirements of Item 1.01,
Entry Into A Material Definitive Agreement, of Form 8-K. We concluded that our transactions with
BP did not meet the criteria requiring disclosure under Item 1.01.

The BP transactions include four separate agreements concerning the sale or purchase of assets.
The agreements operate totally independent of one another. Each of the four agreements is a
separate, stand-alone agreement, and the closing of each single agreement is not tied to or
affected by whether or not any of the other agreements are closed.

    U.S. Securities and Exchange Commission

    page 2

    April 14, 2010

Therefore, to determine whether the BP agreements constituted material agreements pursuant to Item
1.01, each of the four agreements was considered individually. The four agreements involve the:
(1) sale of assets in Brazil for $3.2 billion; (2) sale of assets in Azerbaijan for $2.0 billion;
(3) sale of U.S. offshore assets for $1.8 billion; and (4) purchase of 50% of BP’s interest in the
Kirby properties for $0.5 billion.

We assessed the materiality of these individual agreements using a variety of measures, including
the sales and purchase amounts as a percentage of our 2009 total assets, the properties’ percentage
of our 2009 pre-tax discounted future net revenues (including the value of the properties
classified as discontinued operations), the properties’ percentage of our 2009 proved oil, gas and
NGL reserves (including the reserves classified as discontinued operations), and the properties’
percentage of our 2009 production of oil, gas and NGLs (including production classified as
discontinued operations). These materiality measures for each of the four agreements were as
follows:

    Brazil

    % of total assets

    10.8
    %

    % of proved oil, gas and NGL reserves

    0.2
    %

    % of oil, gas and NGL production

    1.4
    %

    % of pre-tax discounted future net revenues

    0.2
    %

    Azerbaijan

    % of total assets

    6.7
    %

    % of proved oil, gas and NGL reserves

    2.2
    %

    % of oil, gas and NGL production

    2.4
    %

    % of pre-tax discounted future net revenues

    6.9
    %

    U.S. Offshore

    % of total assets

    6.1
    %

    % of proved oil, gas and NGL reserves

    1.9
    %

    % of oil, gas and NGL production

    2.4
    %

    % of pre-tax discounted future net revenues

    3.5
    %

    Kirby

    % of total assets

    1.7
    %

    % of proved oil, gas and NGL reserves

    n/a

    % of oil, gas and NGL production

    n/a

    % of pre-tax discounted future net revenues

    n/a

Based on these comparisons, we concluded that none of the agreements were material agreements for
purposes of Item 1.01.

We will file a Form 8-K to the extent that the completion of these or other planned divestiture
activities trigger the requirement to file a Form 8-K pursuant to Item 2.01.

    U.S. Securities and Exchange Commission

    page 3

    April 14, 2010

Form 10-K for the Fiscal Year Ended December 31, 2009

Presentation of Discontinued Operations, page 6

SEC Comment

    2.

    We note your disclosure which states that U.S. Offshore operations do not qualify as
discontinued operations under accounting rules for the fiscal year ended December 31, 2009.
Please provide your analysis in accordance with ASC Topic 205-20-45-1 which demonstrates that
these operations did not qualify to be reported as discontinued operations.

Response

The identification of the appropriate “component of an entity” is a key factor in properly applying
the guidelines surrounding reporting of discontinued operations. The FASB ASC glossary states that
“a component of an entity comprises operations and cash flows that can be clearly distinguished,
operationally and for financial reporting purposes, from the rest of the entity.” Devon follows the
full cost method of accounting for its oil and gas operations. In applying the concepts of ASC
Topic 205-20-45-1 to our planned divestiture of assets, we concluded that our “components of an
entity” were most appropriately defined to be our individual cost centers. Our analysis of this
matter was supported by the “Working Draft of AICPA Audit and Accounting Guide — Entities With Oil
and Gas Producing Activities” issued on October 9, 2009. Section 5.53 of this guide reads as
follows:

“Under the impairment or disposal of long lived assets subsections of FASB ASC 360-10 and
205-20-55, the sale of an oil and gas property qualifies for discontinued operations
reporting under certain circumstances for entities applying the successful efforts method.
For entities applying the full cost method, the AcSEC believes that a component of an
entity, which, according to the FASB ASC glossary, comprises operations and cash flows that
can be clearly distinguished, operationally and for financial reporting purposes, from the
rest of the entity and may be a reportable segment or an operating segment, a reporting
unit, a subsidiary, or an asset group, would be an individual cost center, and, therefore,
discontinued operations reporting would not be appropriate unless the entire cost center
was disposed. If an entire cost center is disposed, reporting as discontinued operations
would be appropriate if the other criteria in the impairment or disposal of long lived
assets subsections of FASB ASC 360-10 and 205-20-55 were met.”

Appendix A — Summary of the Successful Efforts and Full Cost Methods of Accounting of this AICPA
guide further states that for full cost companies, with regard to discontinued operations:

“A component (as defined in the impairment or disposal of long lived assets subsections of
FASB ASC 360-10) would be an individual cost center. Unless the entire cost center is
disposed of, reporting as discontinued operations is not appropriate.”

    U.S. Securities and Exchange Commission

    page 4

    April 14, 2010

The U.S. offshore assets we are divesting do not comprise our entire U.S. cost center. In fact,
they represent a relatively small percentage of the U.S. cost center. The U.S. offshore properties
we are divesting represent 4.7% of the total cost center’s 2009 proved oil, gas and NGL reserves,
7.9% of the total cost center’s 2009 production of oil, gas and NGLs and 10.9% of the total cost
center’s 2009 pre-tax discounted future net revenues. Therefore, we concluded that our U.S.
offshore assets being divested do not qualify to be reported as discontinued operations.

Oil, Natural Gas and NGL Marketing, page 7

SEC Comment

    3.

    We note your oil, natural gas and NGL are sold under both long-term and short-term
agreements. Please provide the required disclosure to comply with Item 1207 of Regulation S-K
regarding delivery commitments in future filings or tell us why such disclosures are not
applicable.

Response

We will include the disclosure set forth in Item 1207 in future filings.

Preparation of Reserves Estimates and Reserves Audits, page 20

SEC Comment

    4.

    Expand your discussion of the Director of the Group’s qualifications to specifically his
years of experience and describe in more detail his “relevant experience estimating reserves.”

Response

The Director has been involved with reserves estimation in accordance with SEC definitions and
guidance since 1987. He has experience in reserves estimation for projects in the U.S. (both
onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been
employed by Devon for the past eight years, including the past two in his current position as
Director of Reserves and Economics.

We propose to include this additional disclosure in our future filings.

Proved Oil, Natural Gas and NGL Reserves

Proved Undeveloped Reserves, page 23

SEC Comment

    5.

    You state you developed 81 million barrels equivalent of proved undeveloped reserves in 2009.
This represents approximately 19% of your total proved undeveloped reserves at year end 2008
and 10% of your proved undeveloped reserves at year end 2009. This rate of development of
your proved undeveloped reserves at year end 2009 suggests that it will take approximately 10
years to develop all of your proved undeveloped reserves, assuming that no

    U.S. Securities and Exchange Commission

    page 5

    April 14, 2010

    additional proved undeveloped reserves are added during that time. As proved undeveloped
reserves should generally be developed within five years of initially booking them as
proved, please tell us how you plan to accomplish this.

Response

The calculated years of development you note in your comment is heavily influenced by the
development timeframe associated with our Jackfish project, which is comprised of two heavy-oil
SAGD processing facilities located on our Jackfish lease in Alberta, Canada. The proved
undeveloped reserves for this project are 351 million barrels of oil at year-end 2009. The
conditions controlling the development schedules for this project satisfy the “specific
circumstances” as stated in Regulation S-X 4-10(a)(31)(ii) that justify a development schedule in
excess of five years. Development schedules for the Jackfish reserves are primarily controlled by
the need to keep the processing plants at their full capacity of 35,000 barrels of oil per day per
facility. Processing plant capacity is controlled by factors such as total steam processing
capacity, steam-oil ratio, and air-quality discharge permits. Consequently, the development
schedule for the Jackfish proved undeveloped reserves extends through the year 2025.

All of our previously booked Jackfish proved undeveloped reserves were removed from our proved
reserves classification at year-end 2008 due to the impact of the price reductions that occurred in
2008. Therefore, our 2008 proved undeveloped reserves included no reserves associated with
Jackfish. As disclosed in the last paragraph of page 23 of our 2009 10-K, due to higher oil prices
in 2009, our Jackfish proved undeveloped reserves once again became economic and were added to our
total proved undeveloped reserves at year-end 2009 as revisions due to prices. This addition of
351 million barrels of Jackfish reserves in 2009 caused the calculated overall development rate to
increase to the 10 years noted in your comment.

For our properties other than Jackfish, the development pace of our year-end 2009 proved
undeveloped reserves is approximately equal to the general guideline of five years. Our current
development plans would result in 99% of the year-end 2009 proved undeveloped reserves, excluding
the Jackfish reserves, being developed within the next five years.

SEC Comment

    6.

    We note as a result of 2009 drilling activities, you increased your proved undeveloped
reserves with extensions and discoveries of 316 million barrels equivalent, and converted 81
million barrels equivalent to proved developed reserves. Please provide more specific
disclosure by project on each of your drilling activities and how they contributed to the
increase in your proved undeveloped reserves.

Response

As indicated in the tabular data on page 23, the primary contributors to our increase in proved
undeveloped reserves in 2009 were revisions due to prices and extensions and discoveries.

    U.S. Securities and Exchange Commission

    page 6

    April 14, 2010

The revisions due to prices are explained in the second paragraph following the tabular data. The
extensions and discoveries, which as noted in the tabular data added 316 million barrels equivalent
of proved undeveloped reserves during 2009, are included in the 458 million barrels equivalent of
additions to total proved reserves (both proved developed and proved undeveloped) included in the
reserve reconciliation table on page 133. On pages 134 and 135, we have disclosed the
contributions by project on each of the line item in the reserve reconciliation, including
extensions and discoveries.

In future filings, we propose to include in the discussion of proved undeveloped reserves a
reference to the disclosures of the contributions by project area of all changes to total proved
reserves.

Proved Reserves Cash Flows, page 24

SEC Comment

    7.

    We note footnote (1) to your tabular presentation that states “costs included in future net
revenues are determined in a similar manner” to your future net revenue. Please tell us
specifically what you mean by this disclosure, how you calculated these costs, and if this
represents a change in methodology from prior years.

Response

The wording you have identified in footnote (1) means that costs were estimated in a manner similar
to that used to estimate the oil, gas and NGL prices. Specifically, what we mean is that the
year-end costs included in future net revenues are estimated using averages of several prior
months’ actual costs. Averages of prior months’ costs must be used because not all costs are
incurred on a consistent month-to-month basis throughout a year. This methodology to estimate
year-end costs is consistent with prior years and is consistent with our understanding of common
industry practice.

Exhibits 99.2 and 99.3

SEC Comment

    8.

    We note that the reports in Exhibits 99.2 and 99.3 do not appear to contain the statement
required by Item 1202(a)(8)(iv) of Regulation S-K that the assumptions, data, methods and
procedures used are appropriate for the purpose served by the report. Please obtain a revised
version of each report that includes the required statement.

Response

Exhibit 99.2 begins with a declarative sentence regarding the purpose of the report. The paragraph
continues to state that: “... reserves and income data were estimated based on the definitions and
disclosure guidelines contained in the United States Securities and Exchange Commission Title 17,
Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January
14, 2009 in the Federal Register (SEC regulations). The results of our third party study, completed
on January 18, 2010, are presented herein.” Devon and the third-party preparer suggest that this
language

    U.S. Securities and Exchange Commission

    page 7

    April 14, 2010

declares that the preparer utilized the appropriate data, methods, procedures, and definitions for
the purpose of the report.

Exhibit 99.3, paragraph 1, state